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Documentation Supplement for EPA Base Case v4.10_PTox −

Updates for Proposed Toxics Rule

U.S. Environmental Protection Agency Clean Air Markets Division

1200 Pennsylvania Avenue, NW (6204J) Washington, D.C. 20460

(www.epa.gov/airmarkets)

March 2011

1

This report documents enhancements and updates that were made in EPA Base Case v4.10_PTox Mar20111 to provide capabilities required to perform modeling for the Proposed Toxics Rule. Specifically, the capability to model HCl emissions and controls was added. Existing coal units were given the option to burn natural gas by investing in a coal-to-gas retrofit. The cost and performance assumptions were updated for Activated Carbon Injection (ACI), the emission control particularly designated for mercury emission reductions. In addition, updates were made to the tables of state regulations and NSR and state settlements to reflect changes that had occurred since the previous base case The current report takes the form of a supplement to the documentation report “Documentation for EPA Base Case v4.10 Using the Integrated Planning Model” (August 2010) that can be found on the web at www.epa.gov/airmarkets/progsregs/epa-ipm/BaseCasev410.html. Exhibit 1 contains an abbreviated version of the table of contents of the v4.10 Documentation. Additions and changes found in this Documentation Supplement are shown in red.

1 EPA Base Case v4.10_PTox Mar2011 refers to EPA’s application of the Integrated Planning Model (IPM) of the U.S. power sector that was developed and used in analysis of the Proposed Toxics Rule. For brevity it is often referred to as v4.10_PTox in subsequent pages of this documentation supplement. IPM® is a registered trademark of ICF International.

2

Exhibit 1: Abbreviated table of contents for EPA Base Case v4.10 showing (in red) additions and changes covered in this Documentation Supplement 1 INTRODUCTION 2 MODELING FRAMEWORK 3 POWER SYSTEM OPERATION ASSUMPTIONS Appendix 3-2 State Power Sector Regulations Appendix 3-3 New Source Review (NSR) Settlements Appendix 3-4 State Settlements 4 GENERATING RESOURCES 5 EMISSION CONTROL TECHNOLOGIES ● ● ● 5.3 COAL-TO-GAS CONVERSIONS 5.3.1 Boiler Modifications for Coal-to-Gas Conversions 5.3.2 Natural Gas Pipeline Requirements for Coal-to-Gas Conversions ● ● ● 5.4 MERCURY CONTROL TECHNOLOGIES ● ● ● 5.4.3 Mercury Control Capabilities Mercury Control through SO2 and NOX Retrofits Activated Carbon Injection (ACI) Replaced based on current engineering assessment 5.5 Hydrogen Chloride (HCl) Control Technologies 5.5.1 Chlorine Content of Fuels 5.5.2 HCl Removal Rate Assumptions for Existing and Potential Units 5.5.3 HCl Retrofit Emission Control Options 5.5.3.1 Dry and Wet FGD 5.5.3.2 Dry Sorbent Injection 5.5.4 Fabric Filter (Baghouse) Cost Development ● ● ● Appendix 5-3 Example Cost Calculation Worksheets for 3 ACI Options Appendix 5-4 Example Cost Calculation Worksheets for DSI Appendix 5-5 Example Cost Calculation Worksheets for Fabric Filter (Baghouse) 6 CO2 CAPTURE, TRANSPORT, AND STORAGE 7 SET-UP PARAMETERS AND RULES 8 FINANCIAL ASSUMPTIONS 9 COAL 9.1 COAL MARKET REPRESENTATION IN EPA BASE CASE V4.10 ● ● ● 9.1.3 Coal Quality Characteristics 9.1.4 Emission Factors ● ● ● 10 NATURAL GAS 11 OTHER FUELS AND FUEL EMISSION FACTOR ASSUMPTIONS

New HCl modeling

Updated

New fuel retrofit option

Enhanced to include HCl content of coals

3

Documentation Supplement to Chapter 3 (“Power System Operation Assumptions”)

The tables of State Power Sector Regulations (Appendix 3-2), New Source Review Settlements (Appendix 3-3), and State Settlements (Appendix 3-4) were updated to reflect changes that had occurred since the provisions had been incorporated in EPA Base Case v4.10. The updated tables are included below. ************************************************************************************************************* Appendix 3-2 State Power Sector Regulations included in EPA Base Case v4.10_PTox, Mar2011

State/Region Bill Emission Type Emission Specifications Implementation

Status

Alabama Alabama

Administrative Code Chapter 335-3-8

NOx 0.02 lbs/MMBtu annual PPMDV for combined cycle EGUs which commenced operation after April 1, 2003

2003

Arizona Title 18, Chapter 2, Article 7 Hg

90% removal of Hg content of fuel or 0.0087 lb/GWH-hr annual reduction for all non-cogen coal units > 25 MW

2017

California CA Reclaim Market

NOx 9.68 MTons annual cap for list of entities in Appendix A of "Annual RECLAIM Audit Market Report for the Compliance Year 2005" (304 entities) 1994

SO2 4.292 MTons annual cap for list of entities in Appendix A of "Annual RECLAIM Audit Market Report for the Compliance Year 2005" (304 entities)

Colorado 40 C.F.R. Part 60 Hg

2012 & 2013: 80% reduction of Hg content of fuel or 0.0174 lb/GW-hr annual reduction for Pawnee Station 1 and Rawhide Station 101 2014 through 2016: 80% reduction of Hg content of fuel or 0.0174 lb/GW-hr annual reduction for all coal units > 25 MW 2017 onwards: 90% reduction of Hg content of fuel or 0.0087 lb/GW-hr annual reduction for all coal units > 25 MW

2012

Connecticut

Executive Order 19 and Regulations of Connecticut State Agencies (RCSA)

22a-174-22

NOx 0.15 lbs/MMBtu rate limit in the winter season for all fossil units > 15 MW

2003 Executive Order 19,

RCSA 22a-198 & Connecticut General Statues (CGS) 22a-

198

SO2

0.33 lbs/MMBtu annual rate limit for all Title IV sources > 15 MW 0.55 lbs/MMBtu annual rate limit for all non-Title IV sources > 15 MW

Public Act No. 03-72 & RCSA 22a-198 Hg 90% removal of Hg content of fuel or 0.0087 lb/GW-

hr annual reduction for all coal-fired units 2008

Delaware

Regulation 1148: Control of Stationary Combustion Turbine

EGU Emissions

NOx

0.19 lbs/MMBtu ozone season PPMDV for stationary, liquid fuel fired CT EGUs >1 MW 0.39 lbs/MMBtu ozone season PPMDV for stationary, gas fuel fired CT EGUs >1 MW

2009

Regulation No. 1146: Electric Generating Unit (EGU) Multi-

Pollutant Regulation

NOx 0.125 lbs/MMBtu rate limit of NOx annually for all coal and residual-oil fired units > 25 MW

2009

SO2 0.26 lbs/MMBtu annual rate limit for coal and residual-oil fired units > 25 MW

4


Status

Hg

2012: 80% removal of Hg content of fuel or 0.0174 lb/GW-hr annual reduction for all coal units > 25 MW 2013 onwards: 90% removal of Hg content of fuel or 0.0087 lb/GW-hr annual reduction for all coal units > 25 MW

Georgia

Multipollutant Control for Electric Utility

Steam Generating Units

SCR, FGD, and

Sorbent Injection

Baghouse controls to be installed

The following plants must install controls: Bowen, Branch, Hammond, McDonough, Scherer, Wansley, and Yates

Implementation from 2008

through 2015, depending on

plant and control type

Illinois

Title 35, Section 217.706 NOx

0.25 lbs/MMBtu summer season rate limit for all fossil units > 25 MW 2004

Title 35, Part 225, Subpart B: Control of Hg Emissions from Coal Fired Electric Generation Units

NOx 0.11 lbs/MMBtu annual rate limit and ozone season rate limit for all Dynergy and Ameren coal steam units > 25 MW

2012

SO2

2013 & 2014: 0.33 lbs/MMBtu annual rate limit for all Dynergy and Ameren coal steam units > 25 MW 2015 onwards: 0.25 lbs/MMBtu annual rate limit for all Dynergy and Ameren coal steam units > 25 MW

2013

Hg 90% removal of Hg content of fuel or 0.08 lbs/GW-hr annual reduction for all Ameren and Dynergy coal units > 25 MW

2015

Title 35 Part 225; Subpart F: Combined Pollutant Standards

NOx 0.11 lbs/MMBtu ozone season and annual rate limit for all specified Midwest Gen coal steam units 2012

SO2 0.44 lbs/MMBtu annual rate limit in 2013, decreasing annually to 0.11 lbs/MMBtu in 2019 for all specified Midwest Gen coal steam units

2013

Hg 90% removal of Hg content of fuel or 0.08 lbs/GWh annual reduction for all specified Midwest Gen coal steam units

2015

Kansas NOx Emission

Reduction Rule, K.A.R. 28-19-713a.

NOx 0.20 lbs/MMBtu annual rate limit for Quindaro Unit 2 and 0.26 lbs/MMBtu annual rate limit for Nearman Unit 1.

2012

Louisiana

Title 33 Part III - Chapter 22, Control of Emissions of Nitrogen

Oxides

SO2 1.2 lbs/MMBtu ozone season PPMDV for all single point sources that emit or have the potential to emit 5 tons or more of SO2 into the atmosphere

2005

Title 33 Part III - Chapter 15, Emission Standards for Sulfur

Dioxide

NOx

Various annual rate limits depending on plant and fuel type for facilities within the Baton Rouge Nonattainment Area that collectively have the potential to emit 25 tons or more per year of NOx or facilities within the Region of Influence that collectively have the potential to emit 50 tons or more per year of NOx

2005

Maine

Chapter 145 NOx Control Program NOx

0.22 lbs/MMBtu annual rate limit for all fossil fuel units > 25 MW built before 1995 with a heat input capacity < 750 MMBtu/hr 0.15 lbs/MMBtu annual rate limit for all fossil fuel units > 25 MW built before 1995 with a heat input capacity > 750 MMBtu/hr 0.20 lbs/MMBtu annual rate limit for all fossil fuel fired indirect heat exchangers, primary boilers, and resource recovery units with heat input capacity > 250 MMBtu/hr

2005

Statue 585-B Title 38, Chapter 4: Protection and Improvement of

Air

Hg 25 lbs annual cap for any facility including EGUs 2010

5


Status

Maryland Maryland Healthy Air Act

NOx

3.6 MTons summer cap and 8.3 MTons annual cap for Mirant coal units 0.5 MTons summer cap and 1.4 MTons annual cap for Allegheny coal units 3.6 MTons summer cap and 8.03 MTons annual cap for Constellation coal units.

2009 SO2

2009 through 2012: 23.4 MTons annual cap for Constellation coal units, 24.2 MTons annual cap for Mirant Coal units, and 4.6 MTons annual cap for Allegheny coal units. 2013 onwards: 17.9 MTons annual cap for Constellation coal units, 18.5 MTons annual cap for Mirant Coal units, and 4.6 MTons annual cap for Allegheny coal units.

Hg

2010 through 2012: 80% removal of Hg content of fuel for Mirant, Allegheny, and Constellation coal steam units 2013 onwards: 90% removal of Hg content of fuel for Mirant, Allegheny, and Constellation coal steam units

Massachusetts 310 CMR 7.29

NOx 1.5 lbs/MWh annual GPS for Bayton Point, Mystic Generating Station, Somerset Station, Mount Tom, Canal, and Salem Harbor

2006

SO2 3.0 lbs/MWh annual GPS for Bayton Point, Mystic Generating Station, Somerset Station, Mount Tom, Canal, and Salem Harbor

Hg

2012: 85% removal of Hg content of fuel or 0.00000625 lbs/MWh annual GPS for Brayton Point, Mystic Generating Station, Somerset Station, Mount Tom, Canal, and Salem Harbor 2013 onwards: 95% removal of Hg content of fuel or 0.00000250 lbs/MWh annual GPS for Brayton Point, Mystic Generating Station, Somerset Station, Mount Tom, Canal, and Salem Harbor

Michigan Part 15. Emission

Limitations and Prohibitions - Mercury

Hg 90% removal of Hg content of fuel annually for all coal units > 25 MW 2015

Minnesota Minnesota Hg

Emission Reduction Act


Missouri 10 CSR 10-6.350 NOx

0.25 lbs/MMBtu annual rate limit for all fossil fuel units > 25 MW in the following counties: Bollinger, Butler, Cape Girardeau, Carter, Clark, Crawford, Dent, Dunklin, Gasconade, Iron, Lewis, Lincoln, Madison, Marion, Mississippi, Montgomery, New Madrid, Oregon, Pemiscot, Perry, Phelps, Pike, Ralls, Reynolds, Ripley, St. Charles, St. Francois, Ste. Genevieve, Scott, Shannon, Stoddard, Warren, Washington and Wayne 0.18 lbs/MMBtu annual rate limit for all fossil fuel units > 25 MW the following counties: City of St. Louis, Franklin, Jefferson, and St. Louis 0.35 lbs/MMBtu annual rate limit for all fossil fuel units > 25 MW in the following counties: Buchanan, Jackson, Jasper, Randolph, and any other county not listed

2004

Montana Montana Mercury

Rule Adopted 10/16/06

Hg

0.90 lbs/TBtu annual rate limit for all non-lignite coal units 1.50 lbs/TBtu annual rate limit for all lignite coal units

2010

New Hampshire RSA 125-O: 11-18 Hg

80% reduction of aggregated Hg content of the coal burned at the facilities for Merrimack Units 1 & 2 and Schiller Units 4, 5, & 6

2012

6


Status

ENV-A2900 Multiple pollutant annual

budget trading and banking program

NOx

2.90 MTons summer cap for all fossil steam units > 250 MMBtu/hr operated at any time in 1990 and all new units > 15 MW 3.64 MTons annual cap for Merrimack 1 & 2, Newington 1, and Schiller 4 through 6

2007

SO2 7.29 MTons annual cap for Merrimack 1 & 2, Newington 1, and Schiller 4 through 6

New Jersey

N.J.A.C. 7:27-27.5, 27.6, 27.7, and 27.8 Hg

90% removal of Hg content of fuel annually for all coal-fired units 95% removal of Hg content of fuel annually for all MSW incinerator units

2007

N.J. A. C. Title 7, Chapter 27,

Subchapter 19, Table 1

NOx

2009 - 2012 annual rate limits in lbs/MMBtu for the following technologies: Coal Boilers (Wet Bottom) - 1.0 for tangential and wall-fired, 0.60 for cyclone-fired Coal Boilers (Dry Bottom) - 0.38 for tangential, 0.45 for wall-fired, 0.55 for cyclone-fired Oil and/or Gas or Gas only: 0.20 for tangential, 0.28 for wall-fired, 0.43 for cyclone-fired 2013 & 2014 annual rate limits in lbs/MWh for the following technologies: All Coal Boilers: 1.50 for all Oil and/or Gas: 2.0 for tangential, 2.80 for wall-fired, 4.30 for cyclone-fired Gas only: 2.0 for tangential and wall-fired, 4.30 for cyclone-fired 2015 onward annual rate limits in lbs/MWh for the following technologies: All Coal Boilers: 1.50 for all Oil and/or Gas: 2.0 for fuel heavier than No. 2 fuel oil, 1.0 for No. 2 and lighter fuel oil Gas only: 1.0 for all

2009

N.J. A. C. Title 7, Chapter 27,

Subchapter 19, Table 4

NOx

2.2 lbs/MWh annual GPS for gas-burning simple cycle combustion turbine units 3.0 lbs/MWh annual GPS for oil-burning simple cycle combustion turbine units 1.3 lbs/MWh annual GPS for gas-burning combined cycle CT or regenerative cycle CT units 2.0 lbs/MWh annual GPS for oil-burning combined cycle CT or regenerative cycle CT units

2007

New York

Part 237 NOx 39.91 MTons non-ozone season cap for fossil fuel units > 25 MW 2004

Part 238 SO2 131.36 MTons annual cap for fossil fuel units > 25 MW 2005

Mercury Reduction Program for Coal-

Fired Electric Utility Steam Generating

Units

Hg

786 lbs annual cap through 2014 for all coal fired boiler or CT units >25 MW after Nov. 15, 1990. 0.60 lbs/TBtu annual rate limit for all coal units > 25 MW developed after Nov.15 1990

2010

North Carolina NC Clean

Smokestacks Act: Statute 143-215.107D

NOx 25 MTons annual cap for Progress Energy coal plants > 25 MW and 31 MTons annual cap for Duke Energy coal plants > 25 MW

2007

SO2

2012: 100 MTons annual cap for Progress Energy coal plants > 25 MW and 150 MTons annual cap for Duke Energy coal plants > 25 MW 2013 onwards: 50 MTons annual cap for Progress Energy coal plants > 25 MW and 80 MTons annual cap for Duke Energy coal plants > 25 MW

2009

Oregon Oregon Administrative Rules, Chapter 345,

Division 24 CO2

675 lbs/MWh annual rate limit for new combustion turbines burning natural gas with a CF >75% and all new non-base load plants (with a CE <= 75%) emitting CO2

1997

7


Status

Oregon Utility Mercury Rule - Existing Units

Hg 90% removal of Hg content of fuel reduction or 0.6 lbs/TBtu limitation for all existing coal units >25 MW 2012

Oregon Utility Mercury Rule - Potential Units

Hg 25 lbs rate limit for all potential coal units > 25 MW 2009

Pacific Northwest

Washington State House Bill 3141 CO2

$1.45/Mton cost (2004$) for all new fossil-fuel power plant 2004

Texas

Senate Bill 7 Chapter 101

SO2 273.95 MTons cap of SO2 for all grandfathered units built before 1971 in East Texas Region

2003

NOx Annual cap for all grandfathered units built before 1971 in MTons: 84.48 in East Texas, 18.10 in West Texas, 1.06 in El Paso Region

Chapter 117 NOx

East and Central Texas annual rate limits in lbs/MMBtu for units that came online before 1996: Gas fired units: 0.14 Coal fired units: 0.165 Stationary gas turbines: 0.14

2007

Dallas/Fort Worth Area annual rate limit for utility boilers, auxiliary steam boilers, stationary gas turbines, and duct burners used in an electric power generating system except for CT and CC units online after 1992: 0.033 lbs/MMBtu or 0.50 lbs/MWh output or 0.0033 lbs/MMBtu on system wide heat input weighted average for large utility systems 0.06 lbs/MMBtu for small utility systems Houston/Galveston region annual Cap and Trade (MECT) for all fossil units: 17.57 MTons Beaumont-Port Arthur region annual rate limits for utility boilers, auxiliary steam boilers, stationary gas turbines, and duct burners used in an electric power generating system: 0.10 lbs/MMBtu

Utah

R307-424 Permits: Mercury

Requirements for Electric Generating

Units


Wisconsin NR 428 Wisconsin Administration Code NOx

Annual rate limits in lbs/MMBtu for coal fired boilers > 1,000 MMBtu/hr : Wall fired, tangential fired, cyclone fired, and fluidized bed: 2009: 0.15, 2013 onwards: 0.10 Arch fired: 2009 onwards: 0.18

2009 Annual rate limits in lbs/MMBtu for coal fired boilers between 500 and 1,000 MMBtu/hr: Wall fired: 2009: 0.20; 2013 onwards: 0.17 in 2013 Tangential fired: 2009 onwards: 0.15 Cyclone fired: 2009: 0.20; 2013 onwards: 0.15 Fluidized bed: 2009: 0.15; 2013 onwards: 0.10 Arch fired: 2009 onwards: 0.18

8


Status

Annual rate limits for CTs in lbs/MMBtu: Natural gas CTs > 50 MW: 0.11 Distillate oil CTs > 50 MW: 0.28 Biologically derived fuel CTs > 50 MW: 0.15 Natural gas CTs between 25 and 49 MW: 0.19 Distillate oil CTs between 25 and 49 MW: 0.41 Biologically derived fuel CTs between 25 and 49 MW: 0.15

Annual rate limits for CCs in lbs/MMBtu: Natural gas CCs > 25 MW: 0.04 Distillate oil CCs > 25 MW: 0.18 Biologically derived fuel CCs > 25 MWs: 0.15 Natural gas CCs between 10 and 24 MW: 0.19

Chapter NR 446. Control of Mercury

Emissions Hg

2012 through 2014: 40% reduction in total Hg emissions for all coal-fired units in electric utilities with annual Hg emissions > 100 lbs 2015 onwards: 90% removal of Hg content of fuel or 0.0080 lbs/GW-hr reduction in coal fired EGUs > 150 MW 80% removal of Hg content of fuel or 0.0080 lbs/GW-hr reduction in coal fired EGUs > 25 MW

2010

Notes: Updates to the EPA Base Case v4.10_PTox from EPA Base Case 4.10 include the following:

1) An update of the modeling of SO2 rate limits in Connecticut

2) An update of the modeling of the effective dates of various controls on units in Georgia 3) Addition of two Kansas State Law unit-specific constraints

4) An update of the modeling of NOx rate limits in Louisiana

5) An update of the modeling of the NOx annual and summer caps and SO2 annual cap in Maryland

6) An update of the modeling of the NOx rate limits in New Jersey

9

Appendix 3-3 New Source Review (NSR) Settlements in EPA Base Case v4.10_PTox, Mar2011

Company and Plant State Unit

Settlement Actions

Reference Retire/Repower SO2 control NOx Control PM or Mercury Control Allowance Retirement

Allowance Restriction

Action Effective Date Equipment

Percent Removal or Rate

Effective Date Equipment Rate Effective

Date Equipment Rate Effective Date Retirement Restriction Effective Date

Alabama Power

James H. Miller Alabama Units 3

& 4

Install and operate

FGD continuously

95% 12/31/11 Operate

existing SCR continuously

0.1 05/01/08 0.03 12/31/06

With 45 days of settlement entry, APC must retire 7,538 SO2 emission allowances.

APC shall not sell, trade, or otherwise exchange any Plant Miller excess SO2 emission allowances outside of the APC system

1/1/21 http://www.epa.gov/compliance/resources/cases/civil/caa/alabamapower.html

Minnkota Power Cooperative

Beginning 1/01/2006, Minnkota shall not emit more than 31,000 tons of SO2/year, no more than 26,000 tons beginning 2011, no more than 11,500 tons beginning 1/01/2012. If Unit 3 is not operational by 12/31/2015, then beginning 1/01/2014, the plant wide emission shall not exceed 8,500.

Milton R. Young

Minnesota

Unit 1

Install and continuously

operate FGD

95% if wet FGD, 90% if dry

12/31/11


operate Over-fire AIR, or

equivalent technology

with emission rate < .36

0.36 12/31/09

0.03 if wet FGD,

.015 if dry FGD

Plant will surrender 4,346 allowances for each year 2012 – 2015, 8,693 allowances for years 2016 – 2018, 12,170 allowances for year 2019, and 14,886 allowances/year thereafter if Units 1 – 3 are operational by 12/31/2015. If only Units 1 and 2 are operational by12/31/2015, the plant shall retire 17,886 units in 2020 and thereafter.

Minnkota shall not sell or trade NOx allowances allocated to Units 1, 2, or 3 that would otherwise be available for sale or trade as a result of the actions taken by the settling defendants to comply with the requirements

http://www.epa.gov/compliance/resources/cases/civil/caa/minnkota.html

Unit 2

Design, upgrade,

and continuously

operate FGD

90% 12/31/10


operate over-fire AIR, or

equivalent technology

with emission rate < .36

0.36 12/31/07 0.03 Before 2008

SIGECO

FB Culley Indiana

Unit 1

Repower to

natural gas (or retire)

12/31/06 The provision did not specify an amount of SO2 allowances to be surrendered. It only provided that excess allowances resulting from compliance with NSR settlement provisions must be retired.

http://www.epa.gov/compliance/resources/cases/civil/caa/sigecofb.html Unit 2

Improve and continuously

operate existing

FGD (shared by Units 2 and

3)

95% 06/30/04

Unit 3 Improve and continuously 95% 06/30/04 Operate

Existing 0.1 09/01/03 Install and continuously 0.015 06/30/07

10


Settlement Actions







operate existing

FGD (shared by Units 2 and

3)

SCR Continuously

operate a Baghouse

PSEG FOSSIL

Bergen New Jersey Unit 2

Repower to

combined

cycle

12/31/02

The provision did not specify an amount of SO2 allowances to be surrendered. It only provided that excess allowances resulting from compliance with NSR settlement provisions must be retired.

http://www.epa.gov/compliance/resources/cases/civil/caa/psegllc.html

Hudson New Jersey Unit 2

Install Dry FGD (or approved

alt. technology)

and continually

operate

0.15 12/31/06

Install SCR (or approved

tech) and continually

operate

0.1 05/01/07

Install Baghouse

(or approved technology)

0.015 12/31/06

Mercer New Jersey

Units 1 & 2


alt. technology)

and continually

operate

0.15 12/31/10



operate

0.13 05/01/06

TECO

Big Bend Florida

Units 1 & 2

Existing Scrubber

(shared by Units 1 & 2)

95% (95% or

.25)

09/1/00 (01/01/13) Install SCR 0.1 05/01/09

The provision did not specify an amount of

SO2 allowances to be

surrendered. It only provided that excess allowances

resulting from compliance with NSR settlement provisions must

be retired.

http://www.epa.gov/compliance/resources/cases/civil/caa/teco.html

Unit 3

Existing Scrubber


93% if Units 3 &

4 are operating

2000 (01/01/10) Install SCR 0.1 05/01/09

Unit 4

Existing Scrubber


93% if Units 3 &

4 are operating

06/22/05 Install SCR 0.1 07/01/07

Gannon Florida Six units

Retire all six coal units and

repower at least 550

MW of coal

capacity to

natural gas

12/31/04

WEPCO

WEPCO shall comply with the following system wide average NOx emission rates and total NOx tonnage permissible: by 1/1/2005 an emission rate of 0.27 and 31,500 tons, by 1/1/2007 an emission rate of 0.19 and 23,400 tons, and by 1/1/2013 an emission rate of 0.17 and 17, 400 tons. For SO2 emissions, WEPCO will comply with: by 1/1/2005 an emission rate of 0.76 and 86,900 tons, by 1/1/2007 an emission rate of 0.61 and 74,400 tons, by 1/1/2008 an emission rate of 0.45 and 55,400 tons, and by 1/1/2013 an emission rate of 0.32 and 33,300 tons.

http://www.epa.gov/compliance/resources/cases/civil/c

11


Settlement Actions







Presque Isle Wisconsin

Units 1 – 4

Retire or

install SO2 and NOx

controls

12/31/12


operate FGD (or approved

equiv. tech)

95% or 0.1 12/31/12



operate

0.1 12/31/12





be retired.

aa/wepco.html

Units 5 & 6

Install and operate low NOx burners

12/31/03

Units 7 & 8

Operate existing low NOx burners

12/31/05 Install Baghouse

Unit 9 Operate

existing low NOx burners

12/31/06 Install Baghouse

Pleasant Prairie

Wisconsin

1



control tech)

95% or 0.1 12/31/06

Install and continuously operate SCR (or approved

tech)

0.1 12/31/06

2



control tech)

95% or 0.1 12/31/07


tech)

0.1 12/31/03

Oak Creek Wisconsin

Units 5 & 6



control tech)

95% or 0.1 12/31/12


tech)

0.1 12/31/12

Unit 7



control tech)

95% or 0.1 12/31/12


tech)

0.1 12/31/12

Unit 8



control tech)

95% or 0.1 12/31/12


tech)

0.1 12/31/12

Port Washington

Wisconsin

Units 1 – 4 Retire

12/31/04 for Units 1 – 3. Unit 4 by entry of

consent decree

Valley Wisconsin

Boilers 1 – 4

Operate existing low NOx burner

30 days after entry of consent

decree

VEPCO

The Total Permissible NOx Emissions (in tons) from VEPCO system are: 104,000 in 2003, 95,000 in 2004, 90,000 in 2005, 83,000 in 2006, 81,000 in 2007, 63,000 in 2008 – 2010, 54,000 in 2011, 50,000 in 2012, and 30,250 each year thereafter. Beginning 1/1/2013 they will have a system wide emission rate no greater than 0.15 lb/mmBtu.

12


Settlement Actions







Mount Storm West Virginia

Units 1 – 3

Construct or improve

FGD

95% or 0.15 01/01/05

Install and continuously operate SCR

0.11 01/01/08

On or before March 31 of every year

beginning in 2013 and continuing thereafter,

VEPCO shall surrender

45,000 SO2 allowances.

Chesterfield Virginia

Unit 4 Install and

continuously operate SCR

0.1 01/01/13

Unit 5 Construct or

improve FGD

95% or 0.13 10/12/12


0.1 01/01/12

Unit 6 Construct or

improve FGD

95% or 0.13 01/01/10


0.1 01/01/11

Chesapeake Energy Virginia Units 3

& 4 Install and


0.1 01/01/13

Clover Virginia Units 1 & 2 Improve

FGD 95% or

0.13 09/01/03

Possum Point Virginia Units 3

& 4

Retire and

repower to

natural gas

05/02/03

Santee Cooper

Santee Cooper shall comply with the following system wide averages for NOx emission rates and combined tons for emission of: by 1/01/2005 facility shall comply with an emission rate of 0.3 and 30,000 tons, by 1/1/2007 an emission rate of 0.18 and 25,000 tons, by 1/1/2010 and emission rate of 0.15 and 20,000 tons. For SO2 emission the company shall comply with system wide averages of: by 1/1/2005 an emission rate of 0.92 and 95,000 tons, by 1/1/2007 and emission rate of 0.75 and 85,000 tons, by 1/1/2009 an emission rate of 0.53 and 70 tons, and by 1/1/2011 and emission rate of 0.5 and 65 tons.

http://www.epa.gov/compliance/resources/cases/civil/caa/santeecooper.html

Cross South Carolina

Unit 1

Upgrade and

continuously operate

FGD

95% 06/30/06 Install and


0.1 05/31/04





be retired.

Unit 2

Upgrade and


FGD


Continuously operate SCR

0.11/0.1 05/31/04

and 05/31/07

Winyah South Carolina

Unit 1


operate FGD



0.11/0.1 11/30/04

and 11/30/04

Unit 2


operate FGD



0.12 11/30/04

Unit 3

Upgrade and

continuously operate existing

FGD



0.14/0.12 11/30/2005

and 11/30/08

Unit 4

Upgrade and

continuously operate existing

FGD



0.13/0.12 11/30/05

and 11/30/08

Grainger South Carolina Unit 1

Operate low NOx burner

or more 06/25/04

13


Settlement Actions







stringent technology

Unit 2


or more stringent

technology

05/01/04

Jeffries South Carolina

Units 3, 4


or more stringent

technology

06/25/04

Ohio Edison

Ohio Edison shall achieve reductions of 2,483 tons NOx between 7/1/2005 and 12/31/2010 using any combination of: 1) low sulfur coal at Burger Units 4 and 5, 2) operating SCRs currently installed at Mansfield Units 1 – 3 during the months of October through April, and/or 3) emitting fewer tons than the Plant-Wide Annual Cap for NOx required for the Sammis Plant. Ohio Edison must reduce 24,600 tons system-wide of SO2 by 12/31/2010.

http://www.epa.gov/compliance/resources/cases/civil/caa/ohioedison.html

No later than 8/11/2005, Ohio Edison shall install and operate low NOx burners on Sammis Units 1 - 7 and overfired air on Sammis Units 1,2,3,6, and 7. No later than 12/1/2005, Ohio Edison shall install advanced combustion control optimization with software to minimize NOx emissions from Sammis Units 1 – 5.

W.H. Sammis

Plant Ohio

Unit 1

Install Induct

Scrubber (or approved

equiv. control tech)

50% removal or 1.1

lb/mmBtu

12/31/08

Install SNCR(or approvedalt. tech) &

operate continuously

0.25 10/31/07

Beginning on 1/1/2006, Ohio

Edison may use, sell or transfer any

restricted SO2 only to satisfy

the Operational Needs at the

Sammis, Burger and Mansfield Plant, or new

units within the FirstEnergy System that

comply with a 96% removal for SO2. For calendar year 2006 through 2017, Ohio Edison may

accumulate SO2 allowances for

use at the Sammis,

Burger, and Mansfield plants, or

FirstEnergy units equipped

with SO2 Emission Control

Standards. Beginning in 2018, Ohio Edison shall surrender unused

restricted SO2 allowances.

Unit 2

Install Induct



50% removal or 1.1

lb/mmBtu

12/31/08

Operate existing SNCR

continuously

0.25 02/15/06

Unit 3

Install Induct



50% removal or 1.1

lb/mmBtu

12/31/08

Operate low NOx burners and overfire

air by 12/1/05;

install SNCR(or approvedalt. tech) &

operate continuously by 12/31/07

0.25 12/01/05

and 10/31/07

Unit 4

Install Induct



50% removal or 1.1

lb/mmBtu

06/30/09



0.25 10/31/07

Unit 5

Install Flash Dryer

Absorber or ECO2 (or approved


50% removal or 1.1

lb/mmBtu

06/29/09


Operate Continuously

0.29 03/31/08

14


Settlement Actions







& operate

continuously

Unit 6

Install FGD3 (or

approved equiv.

control tech) &


95% removal or 0.13

lb/mmBtu

06/30/11



"Minimum Extent

Practicable"

06/30/05

Operate Existing

ESP Continuously

0.03 01/01/10

Unit 7

Install FGD (or

approved equiv.

control tech) &


95% removal or 0.13

lb/mmBtu

06/30/11

Operate existing SNCR

Continuously

"Minimum Extent

Practicable"

08/11/05

Operate Existing

ESP Continuously

0.03 01/01/10

Mansfield Plant

Pennsylvania

Unit 1 Upgrade existing

FGD 95% 12/31/05


FGD 95% 12/31/06


FGD 95% 10/31/07

Eastlake Ohio Unit 5

Install low NOx

burners, over-fired

air and SNCR & operate

continuously

"Minimize Emissions

to the Extent

Practicable"

12/31/06

Burger Ohio

Unit 4 Repower with at least

80% biomass fuel, up to 20% low

sulfur coal.

12/31/11

Unit 5 12/31/11

MirantI1,6

System-wide NOx Emission Annual Caps: 36,500 tons 2004; 33,840 tons 2005; 33,090 tons 2006; 28,920 tons 2007; 22,000 tons 2008; 19,650 tons 2009; 16,000 tons 2010 onward. System-wide NOx Emission Ozone Season Caps: 14,700 tons 2004; 13,340 tons 2005; 12,590 tons 2006; 10,190 tons 2007; 6,150 tons 2008 – 2009; 5,200 tons 2010 thereafter. Beginning on 5/1/2008, and continuing for each and every Ozone Season thereafter, the Mirant System shall not exceed a System-wide Ozone Season Emission Rate of 0.150 lb/mmBtu NOx.

http://www.epa.gov/compliance/resources/cases/civil/caa/mirant.html Potomac

River Plant Virginia

Unit 1

Unit 2

Unit 3

Install low NOx

burners (or more

effective tech) &

05/01/04

15


Settlement Actions








Unit 4

Install low NOx

burners (or more

effective tech) & operate

continuously

05/01/04

Unit 5

Install low NOx

burners (or more

effective tech) & operate

continuously

05/01/04

Morgantown Plant Maryland

Unit 1

Install SCR (or approved alt. tech) &


0.1 05/01/07

Unit 2

Install SCR (or approved alt. tech) &


0.1 05/01/08

Chalk Point Maryland

Unit 1


operate FGD (or equiv.

technology)

95% 06/01/10

For each year after Mirant commences

FGD operation at Chalk Point,

Mirant shall surrender the

number of SO2 Allowances equal to the amount by

which the SO2 Allowances

allocated to the Units at the Chalk Point Plant are

greater than the total amount of SO2 emissions allowed under this Section

XVIII.

Unit 2


operate FGD (or equiv.

technology)

95% 06/01/10

Illinois Power

System-wide NOx Emission Annual Caps: 15,000 tons 2005; 14,000 tons 2006; 13,800 tons 2007 onward. System-wide SO2 Emission Annual Caps: 66,300 tons 2005 – 2006; 65,000 tons 2007; 62,000 tons 2008 – 2010; 57,000 tons 2011; 49,500 tons 2012; 29,000 tons 2013 onward.

http://www.epa.gov/compliance/resources/cases/civil/caa/illinoispower.html Baldwin Illinois Units 1

& 2

Install wet or dry FGD

(or approved equiv. alt.

tech) & operate

continuously

0.1 12/31/11

Operate OFA &


0.1 08/11/05

Install & continuously

operate Baghouse

0.015 12/31/10

By year end 2008, Dynergy will surrender 12,000 SO2

emission allowances, by

year end 2009 it will surrender

16


Settlement Actions







Unit 3



tech) & operate

continuously

0.1 12/31/11

Operate OFA and/or

low NOx burners

0.12 until 12/30/12; 0.1 from 12/31/12

08/11/05 and

12/31/12


operate Baghouse

0.015 12/31/10

18,000, by year end 2010 it will

surrender 24,000, any by year end 2011 and each year thereafter it will

surrender 30,000

allowances. If the surrendered

allowances result in

insufficient remaining allowances

allocated to the units

comprising the DMG system,

DMG can request to

surrender fewer SO2

allowances.

Havana Illinois Unit 6



tech) & operate

continuously

1.2 lb/mmBtu

until 12/30/201

2; 0.1 lb/mmBtu

from 12/31/2012 onward

08/11/05 and

12/31/12

Operate OFA and/or

low NOx burners & operate


0.1 08/11/05


operate Baghouse, then install ESP or alt. PM equip

For Bag-house: 0.015

lb/mmBtu; For ESP: 0.03

lb/mmBtu

For Baghouse: 12/31/12; For ESP: 12/31/05

Hennepin Illinois

Unit 1 1.2 07/27/05

Operate OFA

and/or low NOx burners

"Minimum Extent

Practicable"

08/11/05

Install ESP (or equiv. alt.

tech) & continuously

operate ESPs

0.03 12/31/06

Unit 2 1.2 07/27/05

Operate OFA


"Minimum Extent

Practicable"

08/11/05



operate ESPs

0.03 12/31/06

Vermilion Illinois Units 1 & 2 1.2 01/31/07

Operate OFA


"Minimum Extent

Practicable"

08/11/05



operate ESPs

0.03 12/31/10

Wood River Illinois Units 4 & 5 1.2 07/27/05

Operate OFA


"Minimum Extent

Practicable"

08/11/05



operate ESPs

0.03 12/31/05

Kentucky Utilities Company

EW Brown Generating

Station Kentucky Unit 3 Install FGD 97% or

0.100 12/31/10


by 12/31/2012, continuously operate low NOx boiler and OFA.

0.07 12/31/12 Continuously operate ESP 0.03 12/31/10

KU must surrender

53,000 SO2 allowances of 2008 or earlier

vintage by March 1, 2009. All surplus NOx

allowances must be

surrendered through 2020.

SO2 and NOx allowances may not be

used for compliance,

and emissions decreases for purposes of

complying with the Consent

Decree do not earn credits.

http://www.epa.gov/compliance/resources/cases/civil/caa/kucompany.html

Salt River Project Agricultural Improvement and Power District (SRP)

Coronado Generating

Station Arizona

Unit 1 or Unit

2

Immediately begin

continuous operation of

existing FGDs on

both units, install new

95% or 0.08

New FGD installed

by 1/1/2012

Install and continuously operate low NOx burner and SCR

0.32 prior to SCR

installation, 0.080 after

LNB by 06/01/2009, SCR by

06/01/2014

Optimization and

continuous operation of

existing ESPs.

0.03

Optimization begins

immediately, rate limit

begins 01/01/12 (date of

new FGD

Beginning in 2012, all

surplus SO2 allowances for both Coronado

and Springerville

Unit 4 must be


used for compliance,

and emissions decreases for purposes of

http://www.epa.gov/compliance/resources/cases/civil/caa/srp.html

17


Settlement Actions







FGD. installation)

surrendered through 2020.

The allowances limited by this condition may, however, be

used for compliance at a

prospective future plant using BACT

and otherwise specified in par.

54 of the consent decree.

complying with the Consent

Decree do not earn credits.

Unit 1 or Unit

2 Install new

FGD 95% or

0.08 01/01/13

Install and continuously operate low NOx burner

0.32 06/01/11

Optimization begins

immediately, rate limit

begins 01/01/13 (date of

new FGD installation

)

American Electric Power

Eastern System-Wide

Annual

Cap (tons)

Year

Annual Cap (tons) Year

NOx and SO2 allowances that

would have been made available by

emission reductions

pursuant to the Consent

Decree must be surrendered.

NOx and SO2 allowances may not be

used to comply with any of the limits imposed by the Consent

Decree. The Consent Decree

includes a formula for calculating excess NOx allowances

relative to the CAIR

Allocations, and restricts the use of

some. See par. 74-79 for details.

Reducing emissions below the Eastern

System-Wide Annual

Tonnage Limitations for NOx and SO2

earns supercompliance allowances.

http://www.epa.gov/compliance/resources/cases/civil/caa/americanelectricpower1007.html

450,000 2010

96,000 2009

450,000 2011

92,500 2010

420,000 2012

92,500 2011

350,000 2013

85,000 2012

340,000 2014

85,000 2013

275,000 2015

85,000 2014

260,000 2016

75,000 2015

235,000 2017

72,000 2016 and thereafter

184,000 2018

174,000

2019 and thereafter

At least 600MW from various units

West Virginia

Sporn 1 – 4

Retire, retrofit, or re-power

12/31/18

Virginia Clinch River 1 – 3

Indiana

Tanners

Creek 1 – 3

18


Settlement Actions







West Virginia

Kammer

1 – 3

Amos West Virginia

Unit 1


operate FGD

12/31/09 Install and


01/01/08

Unit 2


operate FGD



01/01/09

Unit 3


operate FGD



01/01/08

Big Sandy Kentucky

Unit 1

Burn only coal with no more than

1.75 lb/MMBtu

annual average

Date of entry

Continuously operate low NOx burners

Date of entry

Unit 2


operate FGD



01/01/09

Cardinal Ohio

Unit 1


operate FGD



01/01/09 Continuously operate ESP 0.03 12/31/09

Unit 2


operate FGD




Unit 3


operate FGD



01/01/09

Clinch River Virginia Units 1 – 3

Plant-wide

annual cap:

21,700 tons from 2010 to 2014, then

16,300 after

1/1/2015

2010 – 2014,

2015 and thereafter


Date of entry

Conesville Ohio

Unit 1


Date of entry

Unit 2


Date of entry

Unit 3


12/31/12

Unit 4 Install and




12/31/10

19


Settlement Actions







FGD


FGD 95% 12/31/09


Date of entry


FGD 95% 12/31/09


Date of entry

Gavin Ohio

Unit 1


operate FGD

Date of entry


01/01/09

Unit 2


operate FGD

Date of entry


01/01/09

Glen Lyn Virginia

Units 1 – 3

Units 5, 6


1.75 lb/MMBtu

annual average

Date of entry


Date of entry

Kammer West Virginia

Units 1 – 3

Plant-wide

annual cap:

35,000

01/01/10 Continuously

operate over-fire air

Date of entry

Kanawha River

West Virginia

Units 1, 2


1.75 lb/MMBtu

annual average

Date of entry


Date of entry

Mitchell West Virginia

Unit 1


operate FGD



01/01/09

Unit 2


operate FGD



01/01/09

Mountaineer West Virginia Unit 1


operate FGD



01/01/08

Muskingum River Ohio

Units 1 – 4


12/31/15

Unit 5


operate FGD




Picway Ohio Unit 9 Continuously operate low NOx burners

Date of entry

20


Settlement Actions







Rockport Indiana

Unit 1


operate FGD



12/31/17

Unit 2


operate FGD



12/31/19

Sporn West Virginia Unit 5


12/31/13

Tanners Creek Indiana

Units 1 – 3


1.2 lb/MMBtu

annual average

Date of entry


Date of entry

Unit 4

Burn only coal with no more than 1.2% sulfur

content annual

average

Date of entry

Continuously operate

over-fire air Date of

entry

East Kentucky Power Cooperative Inc.

By 12/31/2009, EKPC shall choose whether to: 1) install and continuously operate NOx controls at Cooper 2 by 12/31/2012 and SO2 controls by 6/30/2012 or 2) retire Dale 3 and Dale 4 by 12/31/2012.

System-wide

System-wide 12-month rolling

tonnage limits apply

12-month rolling limit

(tons)

Start of 12-month

cycle

All units must

operate low NOx boilers

12-month rolling limit

(tons)

Start of 12-month cycle

PM control devices must be operated

continuously system-

wide, ESPs must be

optimized within 270

days of entry date, or

EKPC may choose to

submit a PM Pollution Control

Upgrade Analysis.

0.03 1 year

from entry date

All surplus SO2 allowances

must be surrendered each year,

beginning in 2008.


used to comply with the Consent

Decree. NOx allowances that would become

available as a result of

compliance with the Consent

Decree may not be sold or traded. SO2

and NOx allowances allocated to

EKPC must be used within the EKPC system.

Allowances made available

due to supercompliance may be sold

or traded.


aa/nevadapower.html

57,000 10/01/08 11,500 01/01/08

40,000 07/01/11 8,500 01/01/13

28,000 01/01/13 8,000 01/01/15

21


Settlement Actions







Spurlock Kentucky

Unit 1


operate FGD

95% or 0.1 6/30/2011 Continuously

operate SCR

0.12 for Unit 1 until 01/01/201

3, at which

point the unit limit drops to

0.1. Prior to

01/01/2013, the

combined average

when both units are operating must be no more than 0.1

60 days after entry

Unit 2


operate FGD by

10/1/2008

95% or 0.1 1/1/2009

Continuously operate SCR

and OFA

0.1 for Unit 2, 0.1 combined average

when both units are operating

60 days after entry

Dale Plant Kentucky

Unit 1

Install and continuously operate low NOx burners

by 10/31/2007

0.46 01/01/08

EKPC must surrender 1,000 NOx allowances

immediately under the ARP,

and 3,107 under the NOx

SIP Call. EKPC must also surrender

15,311 SO2 allowances.

Date of entry

http://www.epa.gov/compliance/resources/cases/civil/caa/eastkentuckypower-dale0907.html

Unit 2

Install and continuously operate low NOx burners

by 10/31/2007

0.46 01/01/08

Unit 3

EKPC may

choose to

retire Dale 3 and 4 in lieu

of installi

ng control

s in Coope

r 2

12/31/2012

Unit 4

Cooper Kentucky

Unit 1

Unit 2

If EKPC opts to install

controls rather than

retiring Dale, it must

95% or 0.10

If EKPC elects to

install controls, it

must continuously operate SCR

0.08 (or 90% if

non-SCR technology is used)

12/31/12

22


Settlement Actions







install and continuously

operate FGD or equiv.

technology

or install equiv.

technology

Nevada Power Company

Beginning 1/1/2010, combined NOx emissions from Units 5,6,7, and 8 must be no more than 360 tons per year.

Clark Generating

Station Nevada

Unit 5

Units may only fire

natural gas

Increase

water injection

immediately, then install and operate

ultra-low NOx burners (ULNBs) or equivalent technology.

In 2009, Units 5 and 8 may not emit more than 180

tons combined

5ppm 1-hour

average

12/31/08 (ULNB

installation), 01/30/09

(1-hour average)

Allowances may not be

used to comply with the Consent

Decree, and no allowances made available

due to compliance

with the Consent

Decree may be traded or sold.

http://www.epa.gov/compliance/resources/cases/civil/caa/nevadapower.html

Unit 6 5ppm 1-

hour average

12/31/09 (ULNB


(1-hour average)

Unit 7 5ppm 1-

hour average

12/31/09 (ULNB


(1-hour average)

Unit 8 5ppm 1-

hour average

12/31/08 (ULNB


(1-hour average)

Dayton Power & Light

Non-EPA Settlement of 10/23/2008

Stuart Generating

Station Ohio Station

-wide

Complete installation of FGDs on each unit.

96% or 0.10 07/31/09

Owners may not purchase

any new catalyst with SO2 to SO3 conversion rate greater than 0.5%

0.17 station-

wide

30 days after entry

0.030 lb per unit 07/31/09

NOx and SO2 allowances may not be

used to comply with the

monthly rates specified in the

Consent Decree.

Courtlink document provided by EPA in email

0.17

station-wide

60 days after entry

date

82% including data from periods of malfuncti

ons

7/31/09 through 7/30/11

Install control

technology on one unit

0.10 on any single

unit 12/31/12 Install

rigid-type electro-des in each unit's ESP

12/31/15

82% including data from periods of malfuncti

ons

after 7/31/11

0.15 station-

wide 07/01/12

0.10 station-

wide 12/31/14

PSEG FOSSIL, Amended Consent Decree of November 2006

23


Settlement Actions







Kearny New Jersey

Unit 7 Retire unit 01/01/07

Allowances allocated to

Kearny, Hudson, and Mercer may

only be used for the operational needs of those units, and all

surplus allowances

must be surrendered.

Within 90 days of amended

Consent Decree, PSEG must surrender

1,230 NOx Allowances and

8,568 SO2 Allowances not

already allocated to or generated by the units listed here. Kearny allowances

must be surrendered

with the shutdown of those units.

http://www.epa.gov/compliance/resources/decrees/amended/psegfossil-amended-cd.pdf

Unit 8 Retire unit 01/01/07

Hudson New Jersey Unit 2


alt. technology)

and continually

operate

0.15 12/31/10



operate

0.1 12/31/10

Install Baghouse


0.015 12/31/10

Annual Cap

(tons) Year

Annual Cap (tons) Year

5,547 2007 3,486 2007

5,270 2008 3,486 2008

5,270 2009 3,486 2009

5,270 2010 3,486 2010

Mercer New Jersey

Units 1 &2


alt. technology)

and continually

operate

0.15 12/31/10



operate

0.1 01/01/07

Install Baghouse


0.015 12/31/10

Westar Energy

Jeffrey Energy Center

Kansas All units

Units 1, 2, and 3 have a total annual limit of 6,600 tons of SO2 and an annual rate limit of 0.07 lbs/MMBtu starting 2012 Units 1, 2, and 3 must all install FGDs by 2011 and operate them continuously. FGDs must maintain a 30-Day Rolling Average Unit Removal Efficiency for SO2 of at least 97% or a 30-Day Rolling Average Unit Emission Rate for SO2 of no greater than 0.070 lb/MMBtu.

Units 1-3 must continuously operate Low NOx Combustion Systems by 2012 and achieve and maintain a 30-Day Rolling Average Unit Emission Rate for NOx of no greater than 0.180 lb/MMBtu. One of the three units must install an SCR by 2015 and operate it continuously to maintain a 30-Day Rolling Average Unit Emission Rate for NOx of no greater than 0.080 lb/MMBtu. By 2013 Westar shall elect to either (a) install a second SCR on one of the other JEC Units by 2017 or (b) meet a 0.100 lb/MMBtu Plant-Wide 12-Month Rolling Average Emission Rate and 9.6 MTons annual cap for NOx by 2015

Units 1, 2, and 3 must operate each ESP and FGD system continuously by 2011 and maintain a 0.030 lb/MMBtu PM Emissions Rate. Units 1 and 2’s ESPs must be rebuilt by 2014 in order to meet a 0.030 lb/MMBtu PM Emissions Rate

Duke Energy

Gallagher Indiana

Units 1 & 3

Retire or

repower as

natural gas

1/1/2012

Units 2 & 4

Install Dry sorbent injection

technology

80% 1/1/2012

24


Settlement Actions







American Municipal Power

Gorsuch Station Ohio

Units 2 & 3 Elected to Retire Dec

15, 2010 (must retire by Dec 31, 2012)

http://amppartners.org/new

sroom/amp-to-retire-gorsuch-generating-station/ Units 1

& 4

Hoosier Energy Rural Electric Cooperative

Ratts Indiana Units 1 & 2

Install & continually

operate SNCRS

0.25 12/31/2011 Continuously operate ESP

Annually surrender any NOx and SO2 allowances that Hoosier does not need in order to meet its regulatory

obligations


aa/hoosier.html Merom Indiana

Unit 1

Continusly run current

FGD for 90%

removal and update FGD

for 98% removal by

2012

98% 2012

Continuously operate existing SCRs

0.12

Continuously operate ESP and achieve PM rate no greater than 0.007 by 6/1/12

Unit 2

Continusly run current

FGD for 90%

removal and update FGD

for 98% removal by

2014

98% 2014 Continuously operate ESP and achieve PM rate no greater than 0.007 by 6/1/13

Notes:

1) Updates to the EPA Base Case v4.10_PTox from EPA Base Case 4.10 include the additions of the American Municipal Power settlement, the Hoosier Energy Rural Electric Cooperative settlement, a modification to the control requirements on the Mercer plant under the PSEG Fossil settlement, and an update to the SO2 emission modeling on Jeffrey Energy Center as part of the Westar settlement.

2) This summary table describes New Source Review settlement actions as they are represented in EPA Base Case. The settlement actions are simplified for representation in the model. This table is not intended to be a comprehensive description of all elements of the actual settlement agreements.

3) Settlement actions for which the required emission limits will be effective by the time of the first mapped run year (before 1/1/2012) are built into the database of units used in EPA Base Case ("hardwired"). However, future actions are generally modeled as individual constraints on emission rates in EPA Base Case, allowing the modeled economic situation to dictate whether and when a unit would opt to install controls versus retire.

4) Some control installations that are required by these NSR settlements have already been taken by the affected companies, even if deadlines specified in their settlement haven't occurred yet. Any controls that are already in place are built into EPA Base Case

5) If a settlement agreement requires installation of PM controls, then the controls are shown in this table and reflected in EPA Base Case. If settlement requires optimization or upgrade of existing PM controls, those actions are not included in EPA Base Case.

6) For units for which an FGD is modeled as an emissions constraint in EPA Base Case, EPA used the assumptions on removal efficiencies that are shown in the latest emission control technologies documentation

7) For units for which an FGD is hardwired in EPA Base Case, unless the type of FGD is specified in the settlement, EPA modeling assumes the most cost effective FGD (wet or dry) and corresponding 95% removal efficiency for wet and 90% for dry.

8) For units for which an SCR is modeled as an emissions constraint or is hardwired in EPA Base Case, EPA assumed an emissions rate equal to 10% of the unit's uncontrolled rate, with a floor of .06 lb/MMBtu or used the emission limit if provided.

9) The applicable low NOx burner reduction efficiencies are shown in Table A 3-1:3 in the Base Case documentation materials.

10) EPA included in EPA Base Case the requirements of the settlements as they existed on January 1, 2011.

11) Some of the NSR settlements require the retirement of SO2 allowances. EPA estimated the amount of allowances to be retired from these settlements and adjusted the total Title IV allowances accordingly.

25

Appendix 3-4 State Settlements in EPA Base Case v4.10_PTox, Mar2011


State Enforcement Actions

Retire/Repower SO2 control NOx Control PM Control Mercury Control

Action

Effective Date Equipment

Percent Removal or

Rate Effective

Date Equipment Rate Effective Date Equipment Rate Effective

Date Equipment Rate Effective Date

AES

Greenidge New York

Unit 4

Install FGD 90% 09/01/07 Install SCR 0.15 09/01/07

Unit 3 Install BACT 12/31/09 Install BACT 12/31/09

Westover New York

Unit 8

90% 12/31/10 Install SCR 0.15 12/31/10

Unit 7 Install BACT 12/31/09 Install BACT 12/31/09

Hickling New York

Units 1 & 2 Install BACT 05/01/07 Install BACT 05/01/07

Jennison New York

Units 1 & 2 Install BACT 05/01/07 Install BACT 05/01/07

Niagara Mohawk Power

NRG shall comply with the below annual tonnage limitations for its Huntley and Dunkirk Stations: 2005 is 59,537 tons of SO2 and 10,777 tons of NOx, 2006 is 34,230 of SO2 and 6,772 of NOx, 2007 is 30,859 of SO2 and 6,211 of NOx, 2008 is 22,733 tons of SO2

Huntley New York

Units 63 – 66 Retire Before

2008

Public Service Co. of NM

San Juan New Mexico

Unit 1

State-of-the-

art technology

90%

10/31/08

State-of-the-art

technology 0.3

10/31/08

Operate Baghouse and

demister technology

0.015

12/31/09 Design activated

carbon injection technology (or comparable

tech)

12/31/09

Unit 2 03/31/09 03/31/09 12/31/09 12/31/09

Unit 3 04/30/08 04/30/08 04/30/08 04/30/08

Unit 4 10/31/07 10/31/07 10/31/07 10/31/07

Public Service Co of Colorado

Comanche Colorado

Units 1 & 2

Install and operate

FGD

0.1 lb/mmBtu combined average

07/01/09

Install low-NOx

emission controls

0.15 lb/mmBtu combined average

07/01/09 Install sorbent

injection technology

07/01/09

Unit 3 Install and

operate FGD

0.1 lb/mmBtu

Install and operate

SCR 0.08

Install and operate a fabric

filter dust collection system

0.013 Install sorbent

injection technology

Within 180

days of start-up

Rochester Gas & Electric

Russell Plant New York

Units 1 – 4

Retire all

units

Mirant New York

Lovett Plant New York

Unit 1 Retire 05/07/07

Unit 2 Retire 04/30/08

Note: The TVA settlement with North Carolina was removed from this table to reflect the July 26, 2010 ruling by the U.S. Court of Appeals, Fourth Circuit Court reversing the settlement.

26

Documentation Supplement to Chapter 5 (“Emission Control Technologies”) Chapter 5 covers a number of new capabilities incorporated in EPA Base Case v4.10_PTox. Section 5.3 presents features added to give existing coal units the option to burn natural gas by investing in a coal-to-gas retrofit. Section 5.4.3 describes the comprehensive update of the cost and performance assumptions for activated carbon injection (ACI) for mercury control. Section 5.5 describes the assumptions in v4.10_PTox related to hydrogen chloride (HCl) emission rate and control assumptions. This includes defining the removal rates for existing and new generating units and for wet and dry FGD (section 5.5.3.1). It also involves adding dry sorbent injection (DSI) and fabric filters (sections 5.5.3.2 and 5.5.4 respectively) as retrofit control technologies for HCl removal and developing associated cost and performance assumptions. These changes and additions are presented in full below: ************************************************************************************************************* 5. Emission Control Technologies ● ● ● 5.3 Coal-to-Gas conversions2 In EPA Base Case v4.10_PTox existing coal plants are given the option to burn natural gas in addition to coal by investing in a coal-to-gas retrofit. There are two components of cost in this option: Boiler modification costs and the cost of extending natural gas lateral pipeline spurs from the boiler to a natural gas main transmission line. These two components of cost and their associated performance implications are discussed in the following sections. 5.3.1 Boiler Modifications For Coal-To-Gas Conversions Enabling natural gas firing in a coal boiler typically involves installation of new gas burners and modifications to the ducting, windbox (i.e., the chamber surrounding a burner through which pressurized air is supplied for fuel combustion), and possibly to the heating surfaces used to transfer energy from the exiting hot flue gas to steam (referred to as the “convection pass”). It may also involve modification of environmental equipment. Engineering studies are performed to assess operating characteristics like furnace heat absorption and exit gas temperature; material changes affecting piping and components like superheaters, air (re)heaters, economizers, and recirculating fans; and operational changes to sootblowers, spray flows, air heaters, and emission controls. The following table summarizes the cost and performance assumptions for such boiler modifications as incorporated in Base Case v4.10_PTox. The values in the table were developed by EPA’s engineering staff based on technical papers3 and discussions with industry engineers familiar with such projects. They were designed to be applicable across the existing coal fleet.

2 As discussed here coal-to-gas conversion refers to the modification of an existing boiler to allow it to fire natural gas. It does not refer to the addition of a gas turbine to an existing boiler cycle, the replacement of a coal boiler with a new natural gas combined cycle plant, or to the gasification of coal for use in a natural gas combustion turbine. 3 For an example see Babcock and Wilcox’s White Paper MS-14 “Natural Gas Conversions of Exiting Coal-Fired Boilers” 2010 (www.babcock.com/library/tech-utility.html#14).

27

Table 5-11 Cost and Performance Assumptions for Coal-to-Gas Retrofits

Factor Description Notes Applicability: Existing pulverized coal (PC)

fired and cyclone boiler units of a size greater than 25 MW:

Not applicable for fluidized bed combustion (FBC) and stoker boilers.

Capacity Penalty: None The furnace of a boiler designed to burn coal is oversized for natural gas, and coal boilers include equipment, such as coal mills, that are not needed for gas. As a result, burning gas should have no impact on net power output.

Heat Rate Penalty:

+ 5% When gas is combusted instead of coal, the stack temperature is lower and the moisture loss to stack is higher. This reduces efficiency, which is reflected in an increase in the heat rate.

Incremental Capital Cost:

PC units: $/kW = 250*(75/MW)^0.35 Cyclone units: $/kW = 350*(75/MW)^0.35

The cost function covers new gas burners and piping, windbox modifications, air heater upgrades, gas recirculating fans, and control system modifications. Example for 50 MW PC unit: $/kW = 250*(75/50)^0.35 = 288

Incremental Fixed O&M:

-(0.33)*31.1*(75/MW)^0.1 Due to reduced needs for operators, maintenance materials, and maintenance staff when natural gas combusted, FOM costs decrease by 33%.

Incremental Variable O&M:

= (0.25)*1.74*(75/MW)^0.2 Due to reduced waste disposal and miscellaneous other costs, VOM costs decrease by 25%.

Fuel Cost: Natural gas To obtain natural gas the unit incurs the cost of extending lateral pipeline spurs from the boiler to the local transmission mainline. See section 5.3.2.

NOx emission rate:

50% of existing coal unit NOx emission rate, with a floor of 0.05 lbs/MMBtu

The 0.05 lbs/MMBtu floor is the same as the NOx rate floor for new retrofit SCR on units burning subbituminous coal

SO2 emissions: Zero 5.3.2 Natural Gas Pipeline Requirements For Coal-To-Gas Conversions For every individual coal boiler in the U.S., EPA tasked the gas team at ICF International to

28

determine the miles and associated cost of extending pipeline laterals from each boiler to the interstate natural gas pipeline system. To develop these costs the following principles were applied:

• For each boiler, gas volume was estimated based on size and heat rate. • Direct distance to the closest pipeline was calculated. (The analysis only considered

mainlines with diameters that were 16 inches or greater. The lateral distance represented the shortest distance – “as the crow flies” – between the boiler and the mainline.)

• Gas volume (per day) of the initial lateral was not allowed to exceed more than 10 percent of the estimated capacity of the mainline.

• The mainline capacities were estimated from the pipe’s diameter using the Weymouth equation4.

• If the gas requirement exceeded 10 percent of the estimated capacity of the mainline, the cost of a second lateral to connect to the next closest mainline was calculated.

• This procedure was repeated until the entire capacity required for the boiler was reached.

• Diameters of each lateral were then calculated using the Weymouth equation based on their required capacities.

• The cost of all the laterals was calculated based on the pipeline diameter and mileage required. Thus, the final pipeline cost for each boiler was based on the total miles of laterals required.

Figure 5-1 shows the calculations performed. Figure 5-1 Calculations Performed in Costing Lateral Pipeline Requirement

Mainline Flow Capacity, Qm (million cubic feet per day) Qm = 0.06745 * d 2.667, where d is the diameter of the mainline in inches Required Capacity of Lateral/s for Each Boiler, Ql (million cubic feet per day) Ql = (Boiler Capacity * Heat Rate *24) / 1,030,000, where Boiler Capacity is in MW and the Heat Rate is in Btu/kWh Diameter of Each Lateral, D (inches) D = (14.83 * Ql) 0.37495, where each lateral’s capacity may not exceed 10% of the mainline capacity to which the lateral connects Cost per Lateral, C ($) C = 60,000 *D * Number of Miles

Note: The above calculations assume a pipeline cost of $60,000 per inch-mile based on recently completed projects.

4 The Weymouth equation in classical fluid dynamics is used in calculating compressible gas flow as a function of pipeline diameter and friction factors. It is used for pipe sizing.

29

There are several points to note about the approach. First, for relatively large boilers or in cases where the closest mainline has a relatively small diameter, multiple laterals are required to connect the boiler to the interstate gas transmission grid. This assures that each individual boiler will not become a relatively large portion of a pipelines’ transmission capacity. It also reflects real-world practices where larger gas-fired power plants typically have multiple laterals connecting them to different mainlines. This increases the reliability of their gas supply and provides multiple options for gas purchase allowing them to capture favorable prices from multiple sources of gas supply at different points in time. Second, expansion of mainlines was not included in the boiler specific pipeline cost, because the integrated gas model within IPM already includes corridor expansion capabilities. However, if in future IPM runs, multiple converted boilers are concentrated on a single pipeline along a corridor that includes multiple pipelines, a further assessment may be required to make sure that the mainline expansion is not being understated due to modeled efficiencies that may not actually be available in the field. Figures 5-2 through 5-7 summarize the results of the pipeline costing procedure described above. They provide histograms of the number of laterals required per boiler (Figure 5-2), miles of pipeline required per boiler (Figure 5-3), diameters of the laterals in inches (Figure 5-4), total inch-miles of laterals required per boiler (Figure 5-5), total cost to each boiler in million$ (Figure 5-6), and cost (in $) per kW of boiler capacity (Figure 5-7). Table 5-12 gives a consolidated overview of the information in these figures by showing the minimum, maximum, average, and median values that appear in the figures. Table 5-13 (“Cost of Building Pipelines to Coal Plants”) shows the pipeline costing results for each qualifying existing coal fired unit represented in EPA Base Case v4.10_PTox. Figure 5‐2

0

100

200

300

400

500

600

700

800

1 2 3 4 5 6 7 8

Freq

uency (n=1

294)

Number of Laterals

Number of Laterals Required per Boiler

30

Figure 5‐3

Figure 5‐4

0

50

100

150

200

250

300

0 to 1 1 to 5 5 to 10 10 to 25 25 to 50 50 to 100 100 to 200

200 to 300

300 to 400

More than 400

Freq

uency (n=1

294)

Miles of Pipeline

Miles of Pipeline Required per Boiler

0

100

200

300

400

500

600

700

800

1 to 2 2 to 4 4 to 6 6 to 8 8 to 10 10 to 12 12 to 14 14 to 16 16 to 18 18 to 20 More than 20

Freq

uency (n=2

248)

Diameter of Laterals, in Inches

Diameter of Laterals, in Inches

31

Figure 5‐5

Figure 5‐6

0

50

100

150

200

250

300

1 to 50

50 to 100

100 to 200

200 to 400

400 to 600

600 to 800

800 to 1000

1000 to

1200

1200 to

1400

1400 to

1600

1600 to

1800

1800 to

2000

2000 to

3000

3000 to

4000

4000 to

5000

More than 5000

Freq

uency (n=1

294)

Number of Inch‐Miles per Boiler

Total Inch‐Miles of Laterals Required per Boiler

0

50

100

150

200

250

300

0 to 1 1 to 5 5 to 10 10 to 25 25 to 50 50 to 100 100 to 200

200 to 300

300 to 400

More than 400

Freq

uency (n=1

294)

Cost Increment (Million$)

Total Cost to Each Boiler (Million$)

32

Figure 5‐7

0

50

100

150

200

250

300

0 to 1 1 to 5

5 to 10

10 to 25

25 to 50

50 to 100

100 to 200

200 to 300

300 to 400

400 to 500

500 to 600

600 to 700

700 to 800

800 to 900

900 to 1000

1000 to 1100

1100 to 1200

More than 1200

Freq

uency (n=1

294)

Cost Increment ($)

Cost per kW of Boiler Capacity ($)

33

Table 5-13 Cost of Building Pipelines to Coal Plants

UniqueID_Final Plant Name State

Coal Boiler

Capacity (MW)

Number of

Laterals Required

Miles of New

Pipeline Required to Hook Up Unit (miles)

Total Cost of New Pipeline

($)

Cost of New Pipeline per KW of Coal

Capacity ($/kW)

3_B_1 Barry AL 138 1 1 856,526 6 3_B_2 Barry AL 137 1 1 854,527 6 3_B_3 Barry AL 249 2 8 5,243,996 21 3_B_4 Barry AL 362 2 8 6,578,846 18 3_B_5 Barry AL 750 3 19 16,808,021 22 7_B_1 Gadsden AL 64 1 29 16,488,170 258 7_B_2 Gadsden AL 66 1 29 16,913,408 256 8_B_10 Gorgas AL 690 2 68 64,804,607 94 8_B_6 Gorgas AL 108 1 8 5,481,155 51 8_B_7 Gorgas AL 109 1 8 5,362,968 49 8_B_8 Gorgas AL 165 1 8 5,940,132 36 8_B_9 Gorgas AL 175 1 8 6,126,314 35 10_B_1 Greene County AL 254 1 7 6,058,364 24 10_B_2 Greene County AL 243 1 7 6,006,273 25 26_B_1 E C Gaston AL 254 1 23 20,296,423 80 26_B_2 E C Gaston AL 256 1 23 20,549,257 80 26_B_3 E C Gaston AL 254 1 23 20,403,517 80 26_B_4 E C Gaston AL 256 1 23 20,416,837 80 26_B_5 E C Gaston AL 861 3 163 157,432,294 183 47_B_1 Colbert AL 177 1 0 373,331 2 47_B_2 Colbert AL 177 1 0 373,331 2 47_B_3 Colbert AL 177 1 0 373,331 2 47_B_4 Colbert AL 173 1 0 370,044 2

34

47_B_5 Colbert AL 459 2 4 3,524,413 8 50_B_1 Widows Creek AL 111 2 165 76,835,602 692 50_B_2 Widows Creek AL 111 2 165 76,835,602 692 50_B_3 Widows Creek AL 111 2 165 77,445,655 698 50_B_4 Widows Creek AL 111 2 165 77,445,655 698 50_B_5 Widows Creek AL 111 2 165 73,708,744 664 50_B_6 Widows Creek AL 111 2 165 73,708,744 664 50_B_7 Widows Creek AL 473 3 253 156,623,156 331 50_B_8 Widows Creek AL 464 2 165 138,258,079 298 51_B_1 Dolet Hills LA 650 4 32 24,784,949 38 56_B_1 Charles R Lowman AL 86 1 17 11,062,025 129 56_B_2 Charles R Lowman AL 238 2 44 30,585,021 129 56_B_3 Charles R Lowman AL 238 2 44 30,950,390 130 59_B_1 Platte NE 100 1 26 17,550,190 176 60_B_1 Whelan Energy Center NE 77 1 8 4,771,943 62 60_B_2 Whelan Energy Center NE 220 1 8 6,543,326 30 87_B_1 Escalante NM 247 2 11 5,066,695 21

108_B_SGU1 Holcomb KS 360 4 46 26,657,544 74 113_B_1 Cholla AZ 110 1 28 18,947,152 172 113_B_2 Cholla AZ 275 1 28 26,244,568 95 113_B_3 Cholla AZ 271 1 28 26,736,227 99 113_B_4 Cholla AZ 380 2 58 47,225,178 124 126_B_4 H Wilson Sundt Generating Station AZ 156 1 4 3,325,760 21 127_B_1 Oklaunion TX 690 8 560 324,667,985 471 130_B_1 Cross SC 620 2 240 224,907,896 363 130_B_2 Cross SC 540 2 240 216,115,742 400 130_B_3 Cross SC 580 2 240 217,804,475 376 130_B_4 Cross SC 600 2 240 214,338,942 357 136_B_1 Seminole FL 658 3 153 123,762,396 188 136_B_2 Seminole FL 658 3 153 122,186,247 186

35

160_B_2 Apache Station AZ 175 1 2 1,297,559 7 160_B_3 Apache Station AZ 175 1 2 1,277,332 7 165_B_1 GRDA OK 490 6 296 174,657,509 356 165_B_2 GRDA OK 520 7 415 208,730,810 401 207_B_1 St Johns River Power Park FL 626 3 212 196,013,308 313 207_B_2 St Johns River Power Park FL 626 4 477 307,121,204 491

298_B_LIM1 Limestone TX 831 7 325 193,623,209 233 298_B_LIM2 Limestone TX 858 7 325 200,701,756 234 384_B_71 Joliet 29 IL 259 2 2 1,347,435 5 384_B_72 Joliet 29 IL 259 2 2 1,162,657 4 384_B_81 Joliet 29 IL 259 2 2 1,248,834 5 384_B_82 Joliet 29 IL 259 2 2 1,162,657 4 462_B_55 W N Clark CO 18 1 40 14,508,820 824 462_B_59 W N Clark CO 25 1 40 16,328,260 656 465_B_3 Arapahoe CO 47 1 9 4,410,931 94 465_B_4 Arapahoe CO 121 2 86 42,752,979 353 469_B_1 Cherokee CO 115 2 74 33,550,262 292 469_B_2 Cherokee CO 120 2 74 33,924,698 283 469_B_3 Cherokee CO 165 2 74 43,357,353 263 469_B_4 Cherokee CO 388 2 74 67,384,584 174 470_B_1 Comanche CO 366 2 151 139,124,028 380 470_B_2 Comanche CO 370 2 151 139,986,886 378 470_B_3 Comanche CO 750 4 463 332,375,688 443 477_B_5 Valmont CO 199 1 19 14,716,699 74 492_B_5 Martin Drake CO 46 1 13 6,642,383 144 492_B_6 Martin Drake CO 77 2 127 33,893,437 440 492_B_7 Martin Drake CO 131 2 127 64,243,979 490

525_B_H1 Hayden CO 205 2 78 48,661,086 237 525_B_H2 Hayden CO 300 3 123 81,937,859 273 527_B_1 Nucla CO 100 2 43 11,535,802 115

36

564_B_1 Stanton Energy Center FL 440 2 31 28,104,431 64 564_B_2 Stanton Energy Center FL 446 2 31 27,959,515 63

568_B_BHB3 Bridgeport Station CT 372 3 43 28,557,342 77 593_B_3 Edge Moor DE 86 2 14 6,706,484 78 593_B_4 Edge Moor DE 174 2 14 7,908,368 45 594_B_3 Indian River Generating Station DE 153 1 65 48,452,569 317 594_B_4 Indian River Generating Station DE 405 2 144 88,686,140 219 602_B_1 Brandon Shores MD 643 2 46 42,283,145 66 602_B_2 Brandon Shores MD 643 2 46 42,934,049 67 628_B_1 Crystal River FL 379 2 80 64,036,264 169 628_B_2 Crystal River FL 491 2 80 67,687,999 138 628_B_4 Crystal River FL 722 2 80 37,187,321 52 628_B_5 Crystal River FL 721 2 80 35,020,225 49 641_B_4 Crist FL 78 1 6 3,592,115 46 641_B_5 Crist FL 78 1 6 3,517,484 45 641_B_6 Crist FL 302 2 31 24,092,073 80 641_B_7 Crist FL 472 2 31 30,704,144 65 642_B_1 Scholz FL 49 1 13 6,456,489 132 642_B_2 Scholz FL 49 1 13 6,716,660 137 643_B_1 Lansing Smith FL 162 1 22 17,226,194 106 643_B_2 Lansing Smith FL 195 1 22 18,788,587 96

645_B_BB01 Big Bend FL 391 2 25 18,006,544 46 645_B_BB02 Big Bend FL 391 2 25 17,980,144 46 645_B_BB03 Big Bend FL 364 2 25 19,260,622 53 645_B_BB04 Big Bend FL 447 2 25 20,775,229 46

663_B_B2 Deerhaven Generating Station FL 228 1 12 10,065,696 44 667_B_1 Northside Generating Station FL 275 3 205 97,644,692 355 667_B_2 Northside Generating Station FL 275 3 205 110,541,549 402 676_B_3 C D McIntosh Jr FL 342 1 0 52,953 -

703_B_1BLR Bowen GA 713 2 83 83,854,057 118

37

703_B_2BLR Bowen GA 718 2 83 85,497,920 119 703_B_3BLR Bowen GA 902 3 212 165,111,996 183 703_B_4BLR Bowen GA 929 3 212 168,510,330 181

708_B_1 Hammond GA 112 1 42 27,538,206 246 708_B_2 Hammond GA 112 1 42 27,345,875 244 708_B_3 Hammond GA 112 1 42 27,384,522 245 708_B_4 Hammond GA 510 2 110 102,098,030 200 709_B_1 Harllee Branch GA 266 2 60 43,475,590 163 709_B_2 Harllee Branch GA 325 2 60 47,552,004 146 709_B_3 Harllee Branch GA 509 2 60 57,310,793 113 709_B_4 Harllee Branch GA 507 2 60 57,554,933 114

710_B_MB1 Jack McDonough GA 258 1 8 6,833,915 26 710_B_MB2 Jack McDonough GA 259 1 8 6,833,915 26

727_B_3 Mitchell GA 96 1 67 39,746,899 414 728_B_Y1BR Yates GA 99 1 9 6,092,955 62 728_B_Y2BR Yates GA 105 1 9 6,250,791 60 728_B_Y3BR Yates GA 112 1 9 6,402,249 57 728_B_Y4BR Yates GA 135 1 9 6,719,015 50 728_B_Y5BR Yates GA 137 1 9 6,756,893 49 728_B_Y6BR Yates GA 352 2 23 17,743,087 50 728_B_Y7BR Yates GA 355 2 23 17,648,076 50

733_B_1 Kraft GA 48 1 2 861,799 18 733_B_2 Kraft GA 52 1 2 851,601 16 733_B_3 Kraft GA 102 1 2 1,099,326 11

753_B_ST Crisp Plant GA 10 1 67 20,321,021 2,032 856_B_1 E D Edwards IL 112 2 61 13,738,422 123 856_B_2 E D Edwards IL 273 2 61 46,425,546 170 856_B_3 E D Edwards IL 364 3 125 85,921,187 236

861_B_01 Coffeen IL 340 3 103 68,710,560 202 861_B_02 Coffeen IL 560 3 103 82,715,063 148

38

863_B_05 Hutsonville IL 76 2 67 18,023,856 237 863_B_06 Hutsonville IL 77 1 25 14,411,276 187 864_B_05 Meredosia IL 203 1 18 15,177,107 75 867_B_7 Crawford IL 213 1 19 16,157,648 76 867_B_8 Crawford IL 319 2 43 31,027,338 97 874_B_5 Joliet 9 IL 314 2 2 1,666,759 5 876_B_1 Kincaid Generation LLC IL 584 2 11 8,272,242 14 876_B_2 Kincaid Generation LLC IL 584 2 11 8,186,657 14

879_B_51 Powerton IL 385 2 66 60,857,425 158 879_B_52 Powerton IL 385 2 66 59,892,609 156 879_B_61 Powerton IL 385 2 66 60,703,641 158 879_B_62 Powerton IL 385 2 66 59,892,609 156 883_B_17 Waukegan IL 100 1 15 10,038,571 100 883_B_7 Waukegan IL 328 2 38 29,029,637 89 883_B_8 Waukegan IL 361 2 38 30,956,775 86 884_B_1 Will County IL 151 1 4 3,163,672 21 884_B_2 Will County IL 148 1 4 3,225,873 22 884_B_3 Will County IL 251 2 16 6,254,012 25 884_B_4 Will County IL 510 3 27 19,264,080 38

886_B_19 Fisk Street IL 326 2 50 37,297,455 114 887_B_1 Joppa Steam IL 167 1 1 868,817 5 887_B_2 Joppa Steam IL 167 1 1 868,052 5 887_B_3 Joppa Steam IL 167 1 1 866,518 5 887_B_4 Joppa Steam IL 167 1 1 865,749 5 887_B_5 Joppa Steam IL 167 1 1 874,899 5 887_B_6 Joppa Steam IL 167 1 1 867,286 5 889_B_1 Baldwin Energy Complex IL 624 3 106 79,181,733 127 889_B_2 Baldwin Energy Complex IL 629 3 106 81,560,802 130 889_B_3 Baldwin Energy Complex IL 629 3 106 83,884,301 133 891_B_9 Havana IL 487 2 74 66,810,686 137

39

892_B_1 Hennepin Power Station IL 81 1 14 8,519,227 105 892_B_2 Hennepin Power Station IL 240 1 14 12,775,378 53 897_B_1 Vermilion IL 84 1 9 5,387,282 64 897_B_2 Vermilion IL 213 1 9 7,794,565 37 898_B_4 Wood River IL 105 1 1 414,232 4 898_B_5 Wood River IL 383 2 50 31,960,057 83

963_B_31 Dallman IL 86 2 9 2,538,463 30 963_B_32 Dallman IL 87 2 9 3,674,986 42 963_B_33 Dallman IL 199 2 9 6,103,905 31 963_B_4 Dallman IL 200 2 9 5,241,841 26

976_B_123 Marion IL 120 1 2 1,159,953 10 976_B_4 Marion IL 170 2 5 3,301,244 19 981_B_3 State Line IN 187 1 17 13,401,529 72 981_B_4 State Line IN 303 1 17 16,050,991 53 983_B_1 Clifty Creek IN 217 2 73 46,944,665 216 983_B_2 Clifty Creek IN 217 2 73 46,314,833 213 983_B_3 Clifty Creek IN 217 2 73 46,115,920 213 983_B_4 Clifty Creek IN 217 2 73 46,015,513 212 983_B_5 Clifty Creek IN 217 2 73 45,451,394 209 983_B_6 Clifty Creek IN 217 2 73 45,812,745 211

988_B_U1 Tanners Creek IN 145 2 34 16,615,136 115 988_B_U2 Tanners Creek IN 145 2 34 15,923,309 110 988_B_U3 Tanners Creek IN 200 2 34 20,702,486 104 988_B_U4 Tanners Creek IN 500 2 34 29,541,774 59 990_B_50 Harding Street IN 109 2 19 8,909,894 82 990_B_60 Harding Street IN 109 2 19 8,885,172 82 990_B_70 Harding Street IN 435 2 19 15,879,585 37 991_B_3 Eagle Valley IN 43 1 7 3,124,071 73 991_B_4 Eagle Valley IN 56 1 7 3,485,879 62 991_B_5 Eagle Valley IN 62 1 7 3,503,708 57

40

991_B_6 Eagle Valley IN 99 1 7 4,193,428 42 994_B_1 Petersburg IN 232 3 49 21,334,190 92 994_B_2 Petersburg IN 435 3 49 37,186,537 85 994_B_3 Petersburg IN 540 3 49 41,499,639 77 994_B_4 Petersburg IN 545 3 49 41,426,794 76 995_B_7 Bailly IN 160 1 6 4,734,708 30 995_B_8 Bailly IN 320 1 6 6,131,745 19

996_B_11 Dean H Mitchell IN 110 1 9 6,215,826 57 996_B_4 Dean H Mitchell IN 125 1 9 6,467,171 52 996_B_5 Dean H Mitchell IN 125 1 9 6,298,738 50 996_B_6 Dean H Mitchell IN 125 1 9 6,290,529 50

997_B_12 Michigan City IN 469 2 30 23,673,656 50 1001_B_1 Cayuga IN 479 2 17 14,422,589 30 1001_B_2 Cayuga IN 473 2 17 14,501,320 31 1008_B_1 R Gallagher IN 140 2 68 37,331,906 267 1008_B_2 R Gallagher IN 140 2 68 37,021,229 264 1008_B_3 R Gallagher IN 140 2 68 37,073,612 265 1008_B_4 R Gallagher IN 140 2 68 37,331,906 267 1010_G_1 Wabash River IN 85 1 18 9,993,513 118

1010_G_1A Wabash River IN 189 1 18 13,544,723 72 1010_B_2 Wabash River IN 85 1 18 10,865,630 128 1010_B_3 Wabash River IN 85 1 18 10,562,318 124 1010_B_4 Wabash River IN 85 1 18 10,734,687 126 1010_B_5 Wabash River IN 95 1 18 10,957,573 115 1010_B_6 Wabash River IN 318 2 36 27,172,030 85 1012_B_2 F B Culley IN 90 2 17 7,809,213 87 1012_B_3 F B Culley IN 270 2 17 12,236,461 45 1024_B_5 Crawfordsville IN 11 1 17 4,869,930 459 1024_B_6 Crawfordsville IN 13 1 17 4,869,930 387 1032_B_5 Logansport IN 17 1 33 12,027,095 729

41

1032_B_6 Logansport IN 22 1 33 13,630,519 620 1037_B_2 Peru IN 20 1 35 13,581,293 679 1037_B_5 Peru IN 12 1 35 11,360,979 947 1040_B_1 Whitewater Valley IN 35 1 15 6,598,822 190 1040_B_2 Whitewater Valley IN 63 1 15 8,261,808 132

1043_B_1SG1 Frank E Ratts IN 122 2 21 10,457,087 86 1043_B_2SG1 Frank E Ratts IN 121 2 21 10,319,734 85

1046_B_1 Dubuque IA 35 1 5 2,208,889 62 1046_B_5 Dubuque IA 30 1 5 1,972,563 65 1046_B_6 Dubuque IA 13 1 5 1,467,704 111 1047_B_2 Lansing IA 11 1 55 17,428,351 1,542 1047_B_3 Lansing IA 37 1 55 26,822,979 733 1047_B_4 Lansing IA 261 1 55 51,934,638 199 1048_B_2 Milton L Kapp IA 211 1 12 10,197,479 48 1058_B_2 Sixth Street IA 14 1 26 8,461,946 622 1058_B_3 Sixth Street IA 14 1 26 8,917,212 656 1058_B_4 Sixth Street IA 14 1 26 8,917,212 656 1058_B_5 Sixth Street IA 14 1 26 8,917,212 656 1073_B_1 Prairie Creek IA 9 1 27 7,326,935 805 1073_B_2 Prairie Creek IA 10 1 27 7,746,242 759 1073_B_3 Prairie Creek IA 42 1 27 12,682,328 305 1073_B_4 Prairie Creek IA 125 1 27 18,508,829 149 1077_B_1 Sutherland IA 31 1 13 5,431,663 178 1077_B_2 Sutherland IA 31 1 13 5,478,150 176 1077_B_3 Sutherland IA 82 1 13 7,308,613 89 1081_B_7 Riverside IA 3 1 9 1,543,342 617 1081_B_8 Riverside IA 3 1 9 1,543,342 617 1081_B_9 Riverside IA 130 1 9 6,507,714 50 1082_B_1 Walter Scott Jr. Energy Center IA 45 1 7 3,490,912 78 1082_B_2 Walter Scott Jr. Energy Center IA 88 1 7 4,579,541 52

42

1082_B_3 Walter Scott Jr. Energy Center IA 690 2 20 19,594,759 28 1082_B_4 Walter Scott Jr. Energy Center IA 800 3 100 83,501,145 104 1091_B_1 George Neal North IA 135 1 6 4,137,763 31 1091_B_2 George Neal North IA 300 2 94 56,762,413 189 1091_B_3 George Neal North IA 515 2 94 92,812,290 180 1104_B_1 Burlington IA 209 1 56 48,751,365 233 1122_B_7 Ames Electric Services Power Plant IA 33 1 9 4,306,424 130 1122_B_8 Ames Electric Services Power Plant IA 70 1 9 5,719,317 82 1131_B_6 Streeter Station IA 19 1 11 4,085,397 216 1131_B_7 Streeter Station IA 36 1 11 5,297,932 148 1167_B_7 Muscatine Plant #1 IA 22 1 15 6,025,405 276 1167_B_8 Muscatine Plant #1 IA 35 1 15 7,448,934 213 1167_B_9 Muscatine Plant #1 IA 147 1 15 11,166,673 76 1175_B_6 Pella IA 15 1 34 11,121,998 741 1175_B_7 Pella IA 13 1 34 10,691,186 835 1217_B_1 Earl F Wisdom IA 38 1 5 2,119,776 57 1218_B_1 Fair Station IA 23 1 13 4,940,202 211 1218_B_2 Fair Station IA 41 1 13 5,861,900 143 1239_B_39 Riverton KS 38 1 5 2,600,912 68 1239_B_40 Riverton KS 54 1 5 2,860,706 53 1241_B_1 La Cygne KS 724 2 38 34,344,062 47 1241_B_2 La Cygne KS 682 2 38 33,970,202 50 1250_B_3 Lawrence Energy Center KS 48 1 5 2,464,647 51 1250_B_4 Lawrence Energy Center KS 110 1 5 3,255,157 30 1250_B_5 Lawrence Energy Center KS 366 2 41 33,321,767 91 1252_B_10 Tecumseh Energy Center KS 129 1 20 14,251,148 110 1252_B_9 Tecumseh Energy Center KS 74 1 20 12,396,350 168 1295_B_1 Quindaro KS 72 1 0 291,231 4 1295_B_2 Quindaro KS 111 1 0 350,406 3

1353_B_BSU1 Big Sandy KY 260 2 13 9,325,001 36

43

1353_B_BSU2 Big Sandy KY 800 3 28 22,413,123 28 1355_B_1 E W Brown KY 94 1 11 6,988,397 74 1355_B_2 E W Brown KY 160 1 11 8,028,683 50 1355_B_3 E W Brown KY 422 2 27 22,420,126 53 1356_B_1 Ghent KY 475 2 72 62,221,800 131 1356_B_2 Ghent KY 469 2 72 60,732,185 129 1356_B_3 Ghent KY 478 2 72 61,354,347 128 1356_B_4 Ghent KY 478 2 72 61,336,293 128 1357_B_4 Green River KY 68 1 23 13,703,486 202 1357_B_5 Green River KY 95 1 23 14,284,315 150 1361_B_5 Tyrone KY 71 1 29 16,305,568 230 1363_B_4 Cane Run KY 155 2 69 40,785,891 263 1363_B_5 Cane Run KY 168 2 69 42,701,837 254 1363_B_6 Cane Run KY 240 3 118 64,697,971 270 1364_B_1 Mill Creek KY 303 3 128 82,282,642 272 1364_B_2 Mill Creek KY 301 3 128 82,811,245 275 1364_B_3 Mill Creek KY 391 3 128 91,832,381 235 1364_B_4 Mill Creek KY 477 3 128 98,648,172 207 1374_B_1 Elmer Smith KY 132 1 6 4,260,976 32 1374_B_2 Elmer Smith KY 261 1 6 5,968,374 23 1378_B_1 Paradise KY 616 3 122 71,081,976 115 1378_B_2 Paradise KY 602 2 73 60,900,519 101 1378_B_3 Paradise KY 977 3 122 112,779,002 115 1379_B_1 Shawnee KY 133 1 7 4,919,734 37 1379_B_10 Shawnee KY 124 1 7 5,111,900 41 1379_B_2 Shawnee KY 134 1 7 4,937,195 37 1379_B_3 Shawnee KY 134 1 7 4,937,195 37 1379_B_4 Shawnee KY 134 1 7 4,937,195 37 1379_B_5 Shawnee KY 134 1 7 4,937,195 37 1379_B_6 Shawnee KY 134 1 7 4,937,195 37

44

1379_B_7 Shawnee KY 134 1 7 4,937,195 37 1379_B_8 Shawnee KY 134 1 7 4,937,195 37 1379_B_9 Shawnee KY 134 1 7 4,937,195 37

1381_B_C1 Kenneth C Coleman KY 150 1 13 9,632,325 64 1381_B_C2 Kenneth C Coleman KY 150 1 13 9,632,325 64 1381_B_C3 Kenneth C Coleman KY 155 1 13 9,753,637 63 1382_B_H1 HMP&L Station Two Henderson KY 153 2 8 4,675,164 31 1382_B_H2 HMP&L Station Two Henderson KY 159 2 8 4,777,427 30 1383_B_R1 Robert A Reid KY 65 1 2 1,099,308 17 1384_B_1 Cooper KY 116 1 32 20,622,529 178 1384_B_2 Cooper KY 225 1 32 26,316,589 117 1385_B_1 Dale KY 27 1 4 1,766,472 65 1385_B_2 Dale KY 27 1 4 1,773,806 66 1385_B_3 Dale KY 75 1 4 2,378,590 32 1385_B_4 Dale KY 75 1 4 2,378,590 32 1393_B_6 R S Nelson LA 550 3 9 8,013,893 15 1552_B_1 C P Crane MD 200 2 45 28,572,945 143 1552_B_2 C P Crane MD 200 2 45 28,389,222 142 1554_B_2 Herbert A Wagner MD 135 1 22 16,819,534 125 1554_B_3 Herbert A Wagner MD 324 1 22 21,800,677 67 1570_B_11 R Paul Smith Power Station MD 87 2 27 13,234,070 152 1570_B_9 R Paul Smith Power Station MD 28 1 12 4,785,577 171 1571_B_1 Chalk Point LLC MD 341 1 1 1,452,650 4 1571_B_2 Chalk Point LLC MD 342 1 1 1,453,966 4 1572_B_1 Dickerson MD 182 2 9 5,429,574 30 1572_B_2 Dickerson MD 182 2 9 5,421,348 30 1572_B_3 Dickerson MD 182 2 9 5,454,113 30 1573_B_1 Morgantown Generating Plant MD 624 3 99 65,209,623 105 1573_B_2 Morgantown Generating Plant MD 620 3 99 62,360,586 101 1606_B_1 Mount Tom MA 144 1 15 10,827,679 75

45

1619_B_1 Brayton Point MA 244 3 85 44,147,316 181 1619_B_2 Brayton Point MA 244 3 85 44,233,074 181 1619_B_3 Brayton Point MA 612 5 218 146,022,447 239 1626_B_1 Salem Harbor MA 82 1 1 383,498 5 1626_B_2 Salem Harbor MA 80 1 1 379,893 5 1626_B_3 Salem Harbor MA 150 1 1 480,620 3 1695_B_4 B C Cobb MI 156 2 90 51,000,180 327 1695_B_5 B C Cobb MI 156 2 90 50,689,290 325 1702_B_1 Dan E Karn MI 255 1 49 42,287,400 166 1702_B_2 Dan E Karn MI 260 1 49 42,567,978 164 1710_B_1 J H Campbell MI 260 3 188 105,151,164 404 1710_B_2 J H Campbell MI 355 3 188 123,228,381 347 1710_B_3 J H Campbell MI 825 3 188 159,177,335 193 1720_B_7 J C Weadock MI 151 1 48 34,952,956 231 1720_B_8 J C Weadock MI 151 1 48 34,990,691 232 1723_B_1 J R Whiting MI 102 1 14 8,960,245 88 1723_B_2 J R Whiting MI 102 1 14 8,960,245 88 1723_B_3 J R Whiting MI 124 1 14 9,608,933 77 1731_B_1 Harbor Beach MI 103 2 144 65,999,089 641 1732_B_10 Marysville MI 42 1 9 4,558,011 109 1732_B_11 Marysville MI 42 1 9 4,558,011 109 1732_B_12 Marysville MI 42 1 9 4,558,011 109 1732_B_9 Marysville MI 42 1 9 4,558,011 109 1733_B_1 Monroe MI 770 3 63 51,067,983 66 1733_B_2 Monroe MI 785 3 63 51,099,864 65 1733_B_3 Monroe MI 795 3 63 51,321,409 65 1733_B_4 Monroe MI 775 3 63 50,810,782 66 1740_B_2 River Rouge MI 241 2 21 14,040,402 58 1740_B_3 River Rouge MI 272 3 43 18,325,670 67 1743_B_1 St Clair MI 151 1 1 821,585 5

46

1743_B_2 St Clair MI 154 1 1 819,061 5 1743_B_3 St Clair MI 160 1 1 833,199 5 1743_B_4 St Clair MI 151 1 1 818,216 5 1743_B_6 St Clair MI 312 1 1 1,020,896 3 1743_B_7 St Clair MI 440 2 3 1,888,087 4 1745_B_16 Trenton Channel MI 53 1 7 3,518,012 67 1745_B_17 Trenton Channel MI 53 1 7 3,656,788 70 1745_B_18 Trenton Channel MI 53 1 7 3,459,862 66 1745_B_19 Trenton Channel MI 53 1 7 3,400,035 65 1745_B_9A Trenton Channel MI 536 2 28 24,802,480 46 1769_B_5 Presque Isle MI 88 2 310 134,703,955 1,531 1769_B_6 Presque Isle MI 88 2 310 134,119,117 1,524 1769_B_7 Presque Isle MI 85 2 310 142,818,725 1,680 1769_B_8 Presque Isle MI 85 2 310 137,993,296 1,623 1769_B_9 Presque Isle MI 85 2 310 137,993,296 1,623 1771_B_1 Escanaba MI 13 1 100 33,520,946 2,579 1771_B_2 Escanaba MI 13 1 100 33,520,946 2,579 1825_B_3 J B Sims MI 73 1 50 28,170,957 387 1830_B_3 James De Young MI 11 1 58 17,149,007 1,633 1830_B_4 James De Young MI 21 1 58 21,967,043 1,072 1830_B_5 James De Young MI 27 1 58 25,680,113 951 1831_B_1 Eckert Station MI 40 1 24 11,844,286 296 1831_B_2 Eckert Station MI 42 1 24 12,088,759 289 1831_B_3 Eckert Station MI 41 1 24 12,054,339 298 1831_B_4 Eckert Station MI 69 1 24 14,020,209 203 1831_B_5 Eckert Station MI 69 1 24 14,438,857 210 1831_B_6 Eckert Station MI 67 1 24 14,126,816 211 1832_B_1 Erickson Station MI 152 1 22 16,549,274 109 1843_B_2 Shiras MI 20 1 141 51,087,933 2,620 1843_B_3 Shiras MI 41 1 141 67,829,244 1,654

47

1866_B_5 Wyandotte MI 24 1 3 1,197,065 50 1866_B_7 Wyandotte MI 24 1 3 1,148,547 48 1866_B_8 Wyandotte MI 24 1 3 1,273,346 53 1891_B_1 Syl Laskin MN 55 1 20 10,946,407 199 1891_B_2 Syl Laskin MN 55 1 20 10,946,407 199 1893_B_1 Clay Boswell MN 69 1 51 28,426,438 412 1893_B_2 Clay Boswell MN 69 1 51 27,994,647 406 1893_B_3 Clay Boswell MN 351 3 305 209,904,664 599 1893_B_4 Clay Boswell MN 525 3 305 259,254,414 494 1904_B_3 Black Dog MN 94 1 15 9,442,803 100 1904_B_4 Black Dog MN 165 1 15 11,307,091 69 1915_B_1 Allen S King MN 610 3 109 98,379,962 161 1943_B_2 Hoot Lake MN 60 1 31 16,991,480 284 1943_B_3 Hoot Lake MN 84 1 31 19,334,908 230

1961_B_NEPP Austin Northeast MN 29 1 10 4,487,238 153 1979_B_1 Hibbing MN 10 1 14 3,643,086 357 1979_B_2 Hibbing MN 10 1 14 3,643,086 357 1979_B_3 Hibbing MN 10 1 14 3,585,412 352 2008_B_1 Silver Lake MN 9 1 43 12,680,825 1,364 2008_B_2 Silver Lake MN 14 1 43 14,336,096 1,010 2008_B_3 Silver Lake MN 24 1 43 16,834,510 693 2008_B_4 Silver Lake MN 59 1 43 23,408,712 395 2018_B_7 Virginia MN 10 1 6 1,757,260 181 2018_B_9 Virginia MN 10 1 6 1,733,461 179 2022_B_3 Willmar MN 20 1 12 4,429,040 217 2049_B_4 Jack Watson MS 230 1 1 1,059,090 5 2049_B_5 Jack Watson MS 476 2 26 22,151,655 47

2062_B_H1 Henderson MS 11 1 2 599,246 54 2062_B_H3 Henderson MS 18 1 2 715,923 40 2076_B_1 Asbury MO 213 3 141 76,776,545 360

48

2079_B_5A Hawthorn MO 563 2 39 40,971,852 73 2080_B_1 Montrose MO 170 2 59 36,622,937 215 2080_B_2 Montrose MO 164 2 59 36,044,913 220 2080_B_3 Montrose MO 176 2 59 36,984,154 210 2094_B_1 Sibley MO 54 1 12 6,050,087 112 2094_B_2 Sibley MO 54 1 12 5,930,500 110 2094_B_3 Sibley MO 401 2 41 34,896,137 87 2098_B_5 Lake Road MO 14 1 3 1,202,124 83 2098_B_6 Lake Road MO 97 1 3 2,454,909 25 2103_B_1 Labadie MO 597 2 88 86,771,052 145 2103_B_2 Labadie MO 594 2 88 84,880,112 143 2103_B_3 Labadie MO 612 2 88 85,776,583 140 2103_B_4 Labadie MO 612 2 88 85,099,994 139 2104_B_1 Meramec MO 122 2 63 27,322,272 224 2104_B_2 Meramec MO 120 2 63 25,433,774 212 2104_B_3 Meramec MO 269 2 63 49,292,459 183 2104_B_4 Meramec MO 347 3 143 95,551,056 275 2107_B_1 Sioux MO 497 2 53 36,171,805 73 2107_B_2 Sioux MO 497 2 53 36,171,805 73 2123_B_6 Columbia MO 25 1 11 4,577,245 187 2123_B_7 Columbia MO 25 1 11 4,001,683 163 2132_B_1 Blue Valley MO 21 1 10 3,657,281 174 2132_B_2 Blue Valley MO 21 1 10 3,657,281 174 2132_B_3 Blue Valley MO 51 1 10 5,626,006 110 2144_B_4 Marshall MO 5 1 16 3,494,867 713 2144_B_5 Marshall MO 16 1 16 5,547,190 347 2161_B_1 James River Power Station MO 21 1 46 17,279,505 823 2161_B_2 James River Power Station MO 21 1 46 17,279,505 823 2161_B_3 James River Power Station MO 41 1 46 22,905,772 559 2161_B_4 James River Power Station MO 56 1 46 24,300,389 434

49

2161_B_5 James River Power Station MO 97 2 120 55,733,835 575 2167_B_1 New Madrid MO 580 2 41 38,953,400 67 2167_B_2 New Madrid MO 580 2 41 39,162,023 68

2168_B_MB1 Thomas Hill MO 175 1 11 9,239,564 53 2168_B_MB2 Thomas Hill MO 275 1 11 10,753,692 39 2168_B_MB3 Thomas Hill MO 670 2 44 35,713,178 53

2169_B_1 Chamois MO 17 1 36 12,968,063 763 2169_B_2 Chamois MO 49 1 36 18,027,617 368 2171_B_1 Missouri City MO 19 1 17 6,359,232 335 2171_B_2 Missouri City MO 19 1 17 6,359,232 335 2187_B_2 J E Corette Plant MT 158 1 150 117,905,332 746 2240_B_6 Lon Wright NE 15 1 3 877,700 59 2240_B_7 Lon Wright NE 20 1 3 1,018,837 51 2240_B_8 Lon Wright NE 85 1 3 1,624,218 19 2277_B_1 Sheldon NE 105 1 12 8,230,098 78 2277_B_2 Sheldon NE 120 1 12 8,683,755 72 2291_B_1 North Omaha NE 79 1 15 9,059,759 115 2291_B_2 North Omaha NE 111 1 15 10,288,311 93 2291_B_3 North Omaha NE 111 1 15 10,236,486 92 2291_B_4 North Omaha NE 138 2 31 14,642,191 106 2291_B_5 North Omaha NE 224 2 31 20,708,445 92 2324_B_1 Reid Gardner NV 110 1 3 1,972,018 18 2324_B_2 Reid Gardner NV 110 1 3 1,993,430 18 2324_B_3 Reid Gardner NV 110 1 3 2,016,780 18 2324_B_4 Reid Gardner NV 225 1 3 2,524,264 11 2364_B_1 Merrimack NH 113 1 30 20,672,673 184 2364_B_2 Merrimack NH 320 2 60 43,651,526 136 2367_B_4 Schiller NH 48 1 3 1,393,557 29 2367_B_6 Schiller NH 48 1 3 1,344,635 28 2378_B_1 B L England NJ 129 2 94 52,365,737 406

50

2378_B_2 B L England NJ 155 2 94 55,367,158 357 2384_B_8 Deepwater NJ 80 1 9 5,464,709 68 2403_B_2 PSEG Hudson Generating Station NJ 608 4 43 28,685,847 47 2408_B_1 PSEG Mercer Generating Station NJ 324 2 20 14,828,819 46 2408_B_2 PSEG Mercer Generating Station NJ 324 2 20 14,394,239 44 2434_B_10 Howard Down NJ 23 1 22 9,263,690 403 2442_B_1 Four Corners NM 170 1 4 2,915,795 17 2442_B_2 Four Corners NM 170 1 4 2,923,662 17 2442_B_3 Four Corners NM 220 1 4 3,300,614 15 2442_B_4 Four Corners NM 760 4 65 48,280,480 64 2442_B_5 Four Corners NM 760 4 65 48,390,171 64 2451_B_1 San Juan NM 322 2 20 11,031,400 34 2451_B_2 San Juan NM 320 2 20 11,210,066 35 2451_B_3 San Juan NM 495 3 38 25,969,488 52 2451_B_4 San Juan NM 506 3 38 25,016,173 49 2468_G_5 Raton NM 7 1 21 5,429,391 787 2480_B_3 Danskammer Generating Station NY 133 1 13 9,015,718 68 2480_B_4 Danskammer Generating Station NY 236 2 33 21,202,511 90 2526_B_11 AES Westover NY 22 1 3 1,274,492 58 2526_B_12 AES Westover NY 22 1 3 1,289,755 59 2526_B_13 AES Westover NY 84 1 3 2,031,559 24 2527_B_6 AES Greenidge LLC NY 106 1 4 2,599,972 25 2535_B_1 AES Cayuga NY 152 1 14 10,586,859 70 2535_B_2 AES Cayuga NY 153 1 14 10,609,438 69 2549_B_67 C R Huntley Generating Station NY 190 2 9 5,176,646 27 2549_B_68 C R Huntley Generating Station NY 190 2 9 5,176,646 27 2554_B_1 Dunkirk Generating Station NY 75 1 7 3,811,141 51 2554_B_2 Dunkirk Generating Station NY 75 1 7 3,833,477 51 2554_B_3 Dunkirk Generating Station NY 185 2 33 13,407,977 72 2554_B_4 Dunkirk Generating Station NY 185 2 33 13,487,072 73

51

2682_B_10 S A Carlson NY 15 1 19 5,898,034 393 2682_B_12 S A Carlson NY 15 1 19 5,960,664 397 2682_B_9 S A Carlson NY 15 1 19 5,960,664 397 2706_B_1 Asheville NC 191 1 53 42,245,167 221 2706_B_2 Asheville NC 185 1 53 41,997,560 227 2708_B_5 Cape Fear NC 144 1 67 48,101,001 334 2708_B_6 Cape Fear NC 172 1 67 52,415,896 305 2709_B_1 Lee NC 74 1 85 49,597,140 670 2709_B_2 Lee NC 77 1 85 49,400,739 642 2709_B_3 Lee NC 248 3 336 175,013,921 706 2712_B_1 Roxboro NC 369 4 318 165,574,308 449 2712_B_2 Roxboro NC 671 5 501 358,153,400 534

2712_B_3A Roxboro NC 353 4 318 179,209,965 508 2712_B_3B Roxboro NC 353 4 318 164,614,623 467 2712_B_4A Roxboro NC 349 4 318 192,495,589 552 2712_B_4B Roxboro NC 349 4 318 180,621,857 518 2713_B_1 L V Sutton NC 93 2 333 159,333,256 1,713 2713_B_2 L V Sutton NC 102 2 333 157,221,358 1,541 2713_B_3 L V Sutton NC 403 4 767 480,939,460 1,193 2716_B_1 W H Weatherspoon NC 48 1 119 60,915,952 1,269 2716_B_2 W H Weatherspoon NC 49 1 119 61,084,751 1,247 2716_B_3 W H Weatherspoon NC 76 1 119 69,786,937 918 2718_B_1 G G Allen NC 162 1 15 11,286,661 70 2718_B_2 G G Allen NC 162 1 15 11,275,688 70 2718_B_3 G G Allen NC 260 1 15 13,258,122 51 2718_B_4 G G Allen NC 275 1 15 13,456,826 49 2718_B_5 G G Allen NC 265 1 15 13,399,377 51 2720_B_5 Buck NC 38 1 10 4,763,840 127 2720_B_6 Buck NC 38 1 10 4,763,840 127 2720_B_7 Buck NC 38 1 10 4,763,840 125

52

2720_B_8 Buck NC 128 1 10 6,775,198 53 2720_B_9 Buck NC 128 1 10 6,799,947 53 2721_B_5 Cliffside NC 550 2 126 78,126,677 142 2721_B_6 Cliffside NC 800 3 267 156,413,590 196 2723_B_1 Dan River NC 67 1 1 592,542 9 2723_B_2 Dan River NC 67 1 1 586,647 9 2723_B_3 Dan River NC 142 2 2 965,276 7 2727_B_1 Marshall NC 378 2 85 54,785,142 145 2727_B_2 Marshall NC 378 2 85 54,832,904 145 2727_B_3 Marshall NC 657 2 85 58,667,715 89 2727_B_4 Marshall NC 657 2 85 58,648,369 89 2732_B_10 Riverbend NC 133 1 8 5,849,602 44 2732_B_7 Riverbend NC 94 1 8 5,226,437 56 2732_B_8 Riverbend NC 94 1 8 5,276,288 56 2732_B_9 Riverbend NC 133 1 8 5,828,717 44

2790_B_B1 R M Heskett ND 29 1 5 2,173,851 74 2790_B_B2 R M Heskett ND 76 1 5 3,036,810 40 2817_B_1 Leland Olds ND 221 1 26 23,149,954 105 2817_B_2 Leland Olds ND 448 2 59 50,234,609 112

2823_B_B1 Milton R Young ND 250 1 23 21,246,210 85 2823_B_B2 Milton R Young ND 455 2 52 44,411,133 98 2824_B_1 Stanton ND 130 1 26 18,738,173 144 2824_B_10 Stanton ND 57 1 26 13,452,251 234 2828_B_1 Cardinal OH 600 3 58 44,899,302 75 2828_B_2 Cardinal OH 600 3 58 46,258,050 77 2828_B_3 Cardinal OH 630 3 58 49,434,180 78 2830_B_1 Walter C Beckjord OH 94 1 7 4,025,382 43 2830_B_2 Walter C Beckjord OH 94 1 7 3,957,346 42 2830_B_3 Walter C Beckjord OH 128 1 7 4,404,241 34 2830_B_4 Walter C Beckjord OH 150 1 7 4,620,484 31

53

2830_B_5 Walter C Beckjord OH 238 1 7 5,566,075 23 2830_B_6 Walter C Beckjord OH 414 2 39 13,252,021 32 2832_B_6 Miami Fort OH 163 2 31 15,320,273 94 2832_B_7 Miami Fort OH 500 2 31 26,978,826 54 2832_B_8 Miami Fort OH 500 2 31 26,795,622 54 2835_B_7 Ashtabula OH 244 3 147 73,712,911 302 2836_B_10 Avon Lake OH 96 2 94 49,628,104 517 2836_B_12 Avon Lake OH 640 4 251 192,073,460 300 2837_B_1 Eastlake OH 132 2 121 68,778,521 521 2837_B_2 Eastlake OH 132 2 121 68,275,329 517 2837_B_3 Eastlake OH 132 2 121 67,409,064 511 2837_B_4 Eastlake OH 240 3 187 98,897,850 412 2837_B_5 Eastlake OH 597 3 187 146,553,511 245 2838_B_18 Lake Shore OH 245 2 110 81,148,527 331 2840_B_3 Conesville OH 165 2 17 5,179,593 31 2840_B_4 Conesville OH 780 3 36 34,479,228 44 2840_B_5 Conesville OH 375 2 17 13,898,446 37 2840_B_6 Conesville OH 375 2 17 13,806,685 37 2843_B_9 Picway OH 95 1 2 1,213,631 13

2848_B_H-1 O H Hutchings OH 58 1 3 1,541,919 27 2848_B_H-2 O H Hutchings OH 55 1 3 1,489,428 27 2848_B_H-3 O H Hutchings OH 63 1 3 1,528,214 24 2848_B_H-4 O H Hutchings OH 63 1 3 1,503,725 24 2848_B_H-5 O H Hutchings OH 63 1 3 1,575,322 25 2848_B_H-6 O H Hutchings OH 63 1 3 1,578,597 25 2850_B_1 J M Stuart OH 597 2 33 34,998,663 59 2850_B_2 J M Stuart OH 597 2 33 34,359,197 58 2850_B_3 J M Stuart OH 597 2 33 33,709,140 56 2850_B_4 J M Stuart OH 597 2 33 34,791,509 58 2861_B_1 Niles OH 108 1 16 10,610,699 98

54

2861_B_2 Niles OH 108 1 16 10,537,680 98 2864_B_7 R E Burger OH 156 1 1 1,036,633 7 2864_B_8 R E Burger OH 156 1 1 1,058,515 7 2866_B_1 W H Sammis OH 180 1 12 9,298,987 52 2866_B_2 W H Sammis OH 180 1 12 9,339,857 52 2866_B_3 W H Sammis OH 180 1 12 9,257,816 51 2866_B_4 W H Sammis OH 180 1 12 9,232,966 51 2866_B_5 W H Sammis OH 300 2 30 18,766,521 63 2866_B_6 W H Sammis OH 600 4 69 46,052,387 77 2866_B_7 W H Sammis OH 600 4 69 46,307,383 77 2872_B_1 Muskingum River OH 190 1 4 3,481,788 18 2872_B_2 Muskingum River OH 190 1 4 3,456,143 18 2872_B_3 Muskingum River OH 205 1 4 3,526,616 17 2872_B_4 Muskingum River OH 205 1 4 3,427,273 17 2872_B_5 Muskingum River OH 585 2 18 15,822,798 27 2876_B_1 Kyger Creek OH 217 1 17 13,759,604 63 2876_B_2 Kyger Creek OH 217 1 17 13,822,283 64 2876_B_3 Kyger Creek OH 217 1 17 13,822,283 64 2876_B_4 Kyger Creek OH 217 1 17 13,874,156 64 2876_B_5 Kyger Creek OH 217 1 17 13,801,443 64 2878_B_1 Bay Shore OH 136 2 29 15,670,335 115 2878_B_2 Bay Shore OH 138 2 29 16,166,545 117 2878_B_3 Bay Shore OH 142 2 29 16,107,455 113 2878_B_4 Bay Shore OH 215 2 29 18,700,991 87

2908_G_10 Lake Road OH 25 1 45 17,869,176 715 2908_G_11 Lake Road OH 85 2 110 47,569,837 560 2908_G_8 Lake Road OH 25 1 45 17,869,176 715 2908_G_9 Lake Road OH 25 1 45 17,869,176 715 2914_G_3 Dover OH 8 1 13 3,409,244 426 2914_B_4 Dover OH 15 1 13 4,595,500 302

55

2917_B_8 Hamilton OH 33 1 4 1,882,521 57 2917_B_9 Hamilton OH 51 1 4 2,128,420 42 2935_B_10 Orrville OH 13 1 20 6,488,346 503 2935_B_11 Orrville OH 13 1 20 6,488,346 503 2935_B_12 Orrville OH 30 1 20 7,899,993 266 2935_B_13 Orrville OH 23 1 20 7,178,704 312 2936_B_3 Painesville OH 11 1 58 16,231,647 1,546 2936_B_4 Painesville OH 22 1 58 22,301,632 1,037 2936_B_5 Painesville OH 22 1 58 20,902,148 972 2937_B_4 Piqua OH 12 1 17 5,411,688 436 2937_B_5 Piqua OH 12 1 17 5,296,940 427 2937_B_6 Piqua OH 20 1 17 6,429,290 321 2942_B_5 St Marys OH 6 1 26 6,320,195 1,090 2942_B_6 St Marys OH 9 1 26 7,005,188 778 2943_B_1 Shelby Municipal Light Plant OH 12 1 3 1,019,872 85 2943_B_2 Shelby Municipal Light Plant OH 12 1 3 1,041,965 87 2943_G_4 Shelby Municipal Light Plant OH 7 1 3 866,280 124 2952_B_4 Muskogee OK 511 4 136 96,829,197 190 2952_B_5 Muskogee OK 522 4 136 96,922,416 186 2952_B_6 Muskogee OK 515 4 136 95,749,179 186

2963_B_3313 Northeastern OK 450 3 57 44,740,461 99 2963_B_3314 Northeastern OK 450 3 57 44,806,701 100

3098_B_1 Elrama PA 94 1 3 2,086,921 22 3098_B_2 Elrama PA 94 1 3 2,099,683 22 3098_B_3 Elrama PA 103 1 3 2,164,661 21 3098_B_4 Elrama PA 174 2 11 5,496,850 32 3113_B_1 Portland PA 157 1 10 7,355,187 47 3113_B_2 Portland PA 243 1 10 8,616,408 35 3115_B_1 Titus PA 81 1 11 6,152,979 76 3115_B_2 Titus PA 81 1 11 6,188,668 76

56

3115_B_3 Titus PA 81 1 11 6,164,913 76 3118_B_1 Conemaugh PA 850 3 44 28,478,143 34 3118_B_2 Conemaugh PA 850 3 44 28,478,143 34 3122_B_1 Homer City Station PA 620 2 10 9,077,095 15 3122_B_2 Homer City Station PA 614 2 10 8,978,074 15 3122_B_3 Homer City Station PA 650 2 10 9,207,237 14 3130_B_1 Seward PA 261 1 2 1,629,448 6 3130_B_2 Seward PA 261 1 2 1,668,097 6 3131_B_1 Shawville PA 122 1 10 7,200,797 59 3131_B_2 Shawville PA 125 1 10 7,294,959 58 3131_B_3 Shawville PA 175 1 10 8,071,310 46 3131_B_4 Shawville PA 175 1 10 8,071,310 46 3136_B_1 Keystone PA 850 3 19 16,645,580 20 3136_B_2 Keystone PA 850 3 19 16,488,634 19 3138_B_3 New Castle PA 94 1 3 1,719,550 18 3138_B_4 New Castle PA 98 1 3 1,670,431 17 3138_B_5 New Castle PA 134 1 3 1,966,212 15 3140_B_1 PPL Brunner Island PA 344 2 7 4,613,100 13 3140_B_2 PPL Brunner Island PA 397 2 7 5,127,900 13 3140_B_3 PPL Brunner Island PA 754 3 34 29,273,420 39 3149_B_1 PPL Montour PA 750 3 99 78,561,631 105 3149_B_2 PPL Montour PA 750 3 99 78,561,631 105

3152_B_1A Sunbury Generation LP PA 40 1 26 12,190,368 309 3152_B_1B Sunbury Generation LP PA 40 1 26 12,190,368 309 3152_B_2A Sunbury Generation LP PA 40 1 26 12,190,368 309 3152_B_2B Sunbury Generation LP PA 40 1 26 12,190,368 309 3152_B_3 Sunbury Generation LP PA 87 1 26 16,356,969 188 3152_B_4 Sunbury Generation LP PA 128 1 26 18,917,854 148 3161_B_2 Eddystone Generating Station PA 309 3 13 7,788,797 25 3178_B_1 Armstrong Power Station PA 172 1 11 8,120,940 47

57

3178_B_2 Armstrong Power Station PA 171 1 11 8,105,917 47 3179_B_1 Hatfields Ferry Power Station PA 530 2 8 7,227,186 14 3179_B_2 Hatfields Ferry Power Station PA 530 2 8 7,194,169 14 3179_B_3 Hatfields Ferry Power Station PA 530 2 8 7,304,351 14 3181_B_33 Mitchell Power Station PA 277 3 27 11,206,077 40 3251_B_1 H B Robinson SC 176 1 87 66,202,863 376 3264_B_1 W S Lee SC 100 1 1 878,755 9 3264_B_2 W S Lee SC 100 1 1 876,154 9 3264_B_3 W S Lee SC 170 1 1 1,039,925 6

3280_B_CAN1 Canadys Steam SC 105 2 210 94,419,328 899 3280_B_CAN2 Canadys Steam SC 116 2 210 98,698,195 851 3280_B_CAN3 Canadys Steam SC 175 2 210 125,031,058 714 3287_B_MCM1 McMeekin SC 125 1 71 47,542,812 380 3287_B_MCM2 McMeekin SC 125 1 71 48,485,566 388 3295_B_URQ3 Urquhart SC 94 2 107 34,257,609 364 3297_B_WAT1 Wateree SC 350 2 200 149,254,789 426 3297_B_WAT2 Wateree SC 350 2 200 147,815,608 422 3298_B_WIL1 Williams SC 615 2 259 213,418,201 347

3317_B_1 Dolphus M Grainger SC 85 1 158 94,743,575 1,115 3317_B_2 Dolphus M Grainger SC 85 1 158 95,251,225 1,121 3319_B_3 Jefferies SC 153 1 99 74,184,083 485 3319_B_4 Jefferies SC 153 1 99 73,960,402 483 3325_B_1 Ben French SD 22 1 108 40,426,126 1,872 3393_B_1 Allen Steam Plant TN 245 2 33 21,938,571 90 3393_B_2 Allen Steam Plant TN 245 2 33 21,938,571 90 3393_B_3 Allen Steam Plant TN 245 2 33 21,938,571 90 3396_B_1 Bull Run TN 881 3 204 205,971,347 234 3399_B_1 Cumberland TN 1,232 3 81 80,248,498 65 3399_B_2 Cumberland TN 1,233 3 81 80,283,958 65 3403_B_1 Gallatin TN 222 1 2 1,928,621 9

58

3403_B_2 Gallatin TN 222 1 2 1,928,621 9 3403_B_3 Gallatin TN 260 1 2 2,058,185 8 3403_B_4 Gallatin TN 260 1 2 2,058,185 8 3405_B_1 John Sevier TN 176 2 139 78,136,455 444 3405_B_2 John Sevier TN 176 2 139 78,136,455 444 3405_B_3 John Sevier TN 176 2 139 78,136,455 444 3405_B_4 John Sevier TN 176 2 139 78,136,455 444 3406_B_1 Johnsonville TN 106 1 19 12,724,426 120 3406_B_10 Johnsonville TN 141 1 19 13,566,786 96 3406_B_2 Johnsonville TN 106 1 19 12,724,426 120 3406_B_3 Johnsonville TN 106 1 19 12,724,426 120 3406_B_4 Johnsonville TN 106 1 19 12,724,426 120 3406_B_5 Johnsonville TN 106 1 19 12,342,977 116 3406_B_6 Johnsonville TN 106 1 19 12,342,977 116 3406_B_7 Johnsonville TN 141 1 19 13,566,786 96 3406_B_8 Johnsonville TN 141 1 19 13,566,786 96 3406_B_9 Johnsonville TN 141 1 19 13,566,786 96 3407_B_1 Kingston TN 134 2 97 36,622,679 273 3407_B_2 Kingston TN 134 2 97 36,622,679 273 3407_B_3 Kingston TN 134 2 97 36,622,679 273 3407_B_4 Kingston TN 134 2 97 36,622,679 273 3407_B_5 Kingston TN 175 2 97 51,649,364 295 3407_B_6 Kingston TN 175 2 97 51,649,364 295 3407_B_7 Kingston TN 175 2 97 51,649,364 295 3407_B_8 Kingston TN 175 2 97 51,649,364 295 3407_B_9 Kingston TN 175 2 97 51,649,364 295

3470_B_WAP5 W A Parish TX 645 3 6 2,686,937 4 3470_B_WAP6 W A Parish TX 650 3 6 2,974,589 5 3470_B_WAP7 W A Parish TX 565 2 1 1,132,402 2 3470_B_WAP8 W A Parish TX 600 2 1 1,192,947 2

59

3497_B_1 Big Brown TX 575 2 13 5,824,349 10 3497_B_2 Big Brown TX 575 2 13 5,447,670 9 3644_B_1 Carbon UT 67 1 7 3,779,914 56 3644_B_2 Carbon UT 105 2 67 27,882,639 266 3775_B_1 Clinch River VA 235 3 164 88,926,102 378 3775_B_2 Clinch River VA 235 3 164 89,731,011 382 3775_B_3 Clinch River VA 235 3 164 88,097,986 375 3776_B_51 Glen Lyn VA 45 1 17 8,772,437 195 3776_B_52 Glen Lyn VA 45 1 17 8,772,437 195 3776_B_6 Glen Lyn VA 235 2 49 32,250,863 137 3788_B_1 Potomac River VA 88 1 10 6,569,511 75 3788_B_2 Potomac River VA 88 1 10 6,137,038 70 3788_B_3 Potomac River VA 102 1 10 6,137,038 60 3788_B_4 Potomac River VA 102 1 10 6,195,082 61 3788_B_5 Potomac River VA 102 1 10 6,252,233 61 3796_B_3 Bremo Bluff VA 71 1 13 7,856,735 111 3796_B_4 Bremo Bluff VA 156 1 13 9,809,996 63 3797_B_3 Chesterfield VA 100 1 5 3,093,281 31 3797_B_4 Chesterfield VA 166 2 55 25,405,927 153 3797_B_5 Chesterfield VA 310 3 142 88,732,353 286 3797_B_6 Chesterfield VA 658 4 229 159,656,669 243 3803_B_1 Chesapeake VA 111 2 116 56,744,698 511 3803_B_2 Chesapeake VA 111 2 116 59,262,250 534 3803_B_3 Chesapeake VA 156 2 116 66,253,664 425 3803_B_4 Chesapeake VA 217 3 228 109,196,341 503 3809_B_1 Yorktown VA 159 2 120 61,769,959 388 3809_B_2 Yorktown VA 164 2 120 63,285,654 386

3845_B_BW21 Transalta Centralia Generation WA 703 2 158 162,043,992 231 3845_B_BW22 Transalta Centralia Generation WA 703 2 158 162,043,992 231

3935_B_1 John E Amos WV 800 3 33 25,455,486 32

60

3935_B_2 John E Amos WV 800 3 33 25,525,621 32 3935_B_3 John E Amos WV 1,300 4 76 54,359,572 42 3936_B_1 Kanawha River WV 205 2 21 10,004,729 49 3936_B_2 Kanawha River WV 205 2 21 9,969,552 49 3938_B_11 Philip Sporn WV 150 2 28 16,300,090 109 3938_B_21 Philip Sporn WV 150 2 28 16,052,044 107 3938_B_31 Philip Sporn WV 150 2 28 15,982,920 107 3938_B_41 Philip Sporn WV 150 2 28 15,866,234 106 3938_B_51 Philip Sporn WV 450 2 28 25,116,859 56 3942_B_1 Albright WV 73 2 20 5,946,953 81 3942_B_2 Albright WV 73 2 20 5,946,953 81 3942_B_3 Albright WV 137 2 20 10,607,955 77 3943_B_1 Fort Martin Power Station WV 552 2 22 20,856,287 38 3943_B_2 Fort Martin Power Station WV 555 2 22 20,871,288 38 3944_B_1 Harrison Power Station WV 652 5 89 62,842,593 96 3944_B_2 Harrison Power Station WV 642 5 89 62,955,955 98 3944_B_3 Harrison Power Station WV 651 5 89 62,590,340 96 3945_B_7 Rivesville WV 46 2 32 12,443,114 271 3945_B_8 Rivesville WV 91 2 32 16,219,574 178 3946_B_1 Willow Island WV 54 1 3 1,914,114 35 3946_B_2 Willow Island WV 181 2 24 16,815,933 93 3947_B_1 Kammer WV 210 1 1 488,386 2 3947_B_2 Kammer WV 210 1 1 488,025 2 3947_B_3 Kammer WV 210 1 1 488,025 2 3948_B_1 Mitchell WV 800 3 5 4,385,284 5 3948_B_2 Mitchell WV 800 3 5 4,375,301 5 3954_B_1 Mt Storm WV 524 4 152 85,613,330 163 3954_B_2 Mt Storm WV 524 4 152 86,726,251 166 3954_B_3 Mt Storm WV 521 3 92 74,902,071 144 3992_B_7 Blount Street WI 22 1 29 11,189,692 500

61

3992_B_8 Blount Street WI 49 1 29 13,913,394 284 3992_B_9 Blount Street WI 48 1 29 13,824,500 287 4041_B_5 South Oak Creek WI 261 2 45 30,655,617 117 4041_B_6 South Oak Creek WI 264 2 45 30,967,962 117 4041_B_7 South Oak Creek WI 298 2 45 33,064,085 111 4041_B_8 South Oak Creek WI 312 2 45 33,486,899 107 4042_B_1 Valley WI 70 1 5 3,047,663 44 4042_B_2 Valley WI 70 1 5 3,047,663 44 4042_B_3 Valley WI 70 1 5 3,026,671 43 4042_B_4 Valley WI 70 1 5 3,026,671 43 4050_B_3 Edgewater WI 76 1 30 17,941,613 236 4050_B_4 Edgewater WI 321 2 84 55,804,908 174 4050_B_5 Edgewater WI 414 3 174 100,511,909 243 4054_B_1 Nelson Dewey WI 107 2 58 29,322,978 275 4054_B_2 Nelson Dewey WI 111 2 58 29,643,798 267 4072_B_5 Pulliam WI 49 1 10 5,081,019 105 4072_B_6 Pulliam WI 72 2 118 19,051,451 266 4072_B_7 Pulliam WI 88 2 118 36,909,371 420 4072_B_8 Pulliam WI 133 2 118 59,324,062 445 4078_B_1 Weston WI 62 1 73 42,302,848 682 4078_B_2 Weston WI 86 2 204 76,891,284 894 4078_B_3 Weston WI 338 4 535 305,939,828 905 4078_B_4 Weston WI 519 4 535 357,497,756 689 4125_B_5 Manitowoc WI 2 1 28 3,801,699 2,534 4125_B_6 Manitowoc WI 18 1 28 9,652,063 536 4125_B_7 Manitowoc WI 18 1 28 9,262,060 515 4125_B_8 Manitowoc WI 21 1 28 9,726,975 472 4125_B_9 Manitowoc WI 30 1 28 11,236,889 375 4127_B_5 Menasha WI 7 1 10 2,268,040 329

4127_B_B23 Menasha WI 9 1 10 2,770,899 326

62

4127_B_B24 Menasha WI 15 1 10 3,373,140 233 4140_B_B1 Alma WI 18 1 57 19,767,691 1,123 4140_B_B2 Alma WI 18 1 57 19,767,691 1,123 4140_B_B3 Alma WI 21 1 57 21,221,307 1,006 4140_B_B4 Alma WI 51 1 57 28,803,600 565 4140_B_B5 Alma WI 77 1 57 33,564,993 436 4143_B_1 Genoa WI 356 2 142 98,844,475 277 4150_B_5 Neil Simpson WY 15 1 22 7,681,834 526 4151_B_1 Osage WY 10 1 73 22,120,867 2,190 4151_B_2 Osage WY 10 1 73 22,120,867 2,190 4151_B_3 Osage WY 10 1 73 22,120,867 2,190

4158_B_BW41 Dave Johnston WY 106 1 8 5,447,933 51 4158_B_BW42 Dave Johnston WY 106 1 8 5,440,496 51 4158_B_BW43 Dave Johnston WY 220 1 8 7,155,406 33 4158_B_BW44 Dave Johnston WY 330 1 8 8,291,718 25

4162_B_1 Naughton WY 160 1 36 27,629,118 173 4162_B_2 Naughton WY 210 1 36 30,459,162 145 4162_B_3 Naughton WY 330 3 186 95,198,954 288 4259_B_1 Endicott Station MI 50 1 16 8,147,501 163

4271_B_B1 John P Madgett WI 398 2 138 97,551,759 245 4941_B_1 Navajo AZ 750 3 348 312,653,688 417 4941_B_2 Navajo AZ 750 3 348 311,741,926 416 4941_B_3 Navajo AZ 750 3 348 308,739,092 412 6002_B_1 James H Miller Jr AL 684 2 73 72,453,897 106 6002_B_2 James H Miller Jr AL 687 2 73 72,325,000 105 6002_B_3 James H Miller Jr AL 687 2 73 72,389,499 105 6002_B_4 James H Miller Jr AL 688 2 73 72,163,306 105 6004_B_1 Pleasants Power Station WV 639 2 31 34,629,535 54 6004_B_2 Pleasants Power Station WV 639 2 31 34,511,038 54 6009_B_1 White Bluff AR 815 3 30 29,247,265 36

63

6009_B_2 White Bluff AR 825 3 30 29,904,002 36 6016_B_1 Duck Creek IL 335 2 80 65,045,755 194 6017_B_1 Newton IL 557 2 32 21,256,386 38 6017_B_2 Newton IL 569 2 32 21,218,914 37 6018_B_2 East Bend KY 600 3 81 60,069,860 100 6019_B_1 W H Zimmer OH 1,300 4 129 110,317,488 85

6021_B_C1 Craig CO 428 3 62 43,725,334 102 6021_B_C2 Craig CO 428 3 62 44,007,279 103 6021_B_C3 Craig CO 418 3 62 43,820,042 105 6030_B_1 Coal Creek ND 554 2 85 58,252,800 105 6030_B_2 Coal Creek ND 560 2 85 78,618,531 140 6031_B_2 Killen Station OH 615 2 36 32,401,966 53 6034_B_1 Belle River MI 698 4 115 57,929,531 83 6034_B_2 Belle River MI 698 4 115 65,882,626 94 6041_B_1 H L Spurlock KY 315 2 43 34,299,690 109 6041_B_2 H L Spurlock KY 509 2 43 43,854,659 86 6041_B_3 H L Spurlock KY 268 2 43 31,686,751 118 6041_B_4 H L Spurlock KY 268 2 43 30,443,356 114 6052_B_1 Wansley GA 891 3 205 125,379,945 141 6052_B_2 Wansley GA 892 3 205 125,632,090 141

6055_B_2B1 Big Cajun 2 LA 580 2 3 2,561,145 4 6055_B_2B2 Big Cajun 2 LA 575 2 3 2,555,499 4 6055_B_2B3 Big Cajun 2 LA 588 2 3 2,531,971 4

6061_B_1 R D Morrow MS 180 1 8 6,731,374 37 6061_B_2 R D Morrow MS 180 1 8 6,804,328 38

6064_B_N1 Nearman Creek KS 229 2 36 19,542,070 85 6065_B_1 Iatan MO 651 2 23 23,906,085 37 6068_B_1 Jeffrey Energy Center KS 730 2 89 85,285,064 117 6068_B_2 Jeffrey Energy Center KS 730 2 89 86,254,355 118 6068_B_3 Jeffrey Energy Center KS 730 2 89 88,473,899 121

64

6071_B_1 Trimble County KY 383 3 142 97,287,993 254 6071_B_2&3 Trimble County KY 760 3 142 115,264,482 152

6073_B_1 Victor J Daniel Jr MS 514 2 6 5,020,082 10 6073_B_2 Victor J Daniel Jr MS 514 2 6 5,000,070 10 6076_B_1 Colstrip MT 307 2 261 184,856,344 602 6076_B_2 Colstrip MT 307 2 261 184,856,344 602 6076_B_3 Colstrip MT 740 2 261 288,152,024 389 6076_B_4 Colstrip MT 740 2 261 288,152,024 389 6077_B_1 Gerald Gentleman NE 665 2 33 32,410,571 49 6077_B_2 Gerald Gentleman NE 700 2 33 31,478,432 45 6082_B_1 AES Somerset LLC NY 681 6 278 170,834,291 251 6085_B_14 R M Schahfer IN 431 2 36 31,648,586 73 6085_B_15 R M Schahfer IN 472 2 36 32,892,605 70 6085_B_17 R M Schahfer IN 361 2 36 29,462,210 82 6085_B_18 R M Schahfer IN 361 2 36 29,060,625 81 6089_B_B1 Lewis & Clark MT 52 1 19 10,381,544 198 6090_B_1 Sherburne County MN 762 4 230 186,587,670 245 6090_B_2 Sherburne County MN 752 4 230 181,960,628 242 6090_B_3 Sherburne County MN 936 4 230 209,343,996 224 6094_B_1 Bruce Mansfield PA 830 5 83 68,945,809 83 6094_B_2 Bruce Mansfield PA 830 5 83 68,639,498 83 6094_B_3 Bruce Mansfield PA 830 5 83 67,538,385 81 6095_B_1 Sooner OK 535 5 237 138,736,724 259 6095_B_2 Sooner OK 540 5 237 148,708,188 275 6096_B_1 Nebraska City NE 646 2 45 44,246,688 68 6096_B_2 Nebraska City NE 663 2 17 15,623,098 24 6098_B_1 Big Stone SD 470 2 75 63,989,316 136

6101_B_BW91 Wyodak WY 335 3 207 123,430,969 368 6106_B_1SG Boardman OR 585 3 292 156,464,937 267

6113_B_1 Gibson IN 630 3 73 64,635,948 103

65

6113_B_2 Gibson IN 628 3 73 64,690,650 103 6113_B_3 Gibson IN 628 3 73 64,157,149 102 6113_B_4 Gibson IN 622 3 73 64,544,530 104 6113_B_5 Gibson IN 620 3 73 65,515,933 106 6124_B_1 McIntosh GA 157 2 174 98,023,860 626 6136_B_1 Gibbons Creek TX 462 2 8 6,109,161 13 6137_B_1 A B Brown IN 245 3 51 27,652,839 113 6137_B_2 A B Brown IN 245 3 51 27,652,839 113 6138_B_1 Flint Creek AR 528 6 303 183,956,789 348 6139_B_1 Welsh TX 528 2 26 23,265,057 44 6139_B_2 Welsh TX 528 2 26 22,953,307 43 6139_B_3 Welsh TX 528 2 26 22,977,196 44 6146_B_1 Martin Lake TX 750 4 16 13,579,347 18 6146_B_2 Martin Lake TX 750 4 16 13,422,881 18 6146_B_3 Martin Lake TX 750 4 16 13,196,821 18 6147_B_1 Monticello TX 565 2 27 25,810,168 46 6147_B_2 Monticello TX 565 2 27 25,648,477 45 6147_B_3 Monticello TX 750 3 41 37,072,040 49 6155_B_1 Rush Island MO 604 4 218 158,885,720 263 6155_B_2 Rush Island MO 604 4 218 153,186,703 254 6165_B_1 Hunter UT 430 2 94 81,186,634 189 6165_B_2 Hunter UT 430 2 94 81,003,689 188 6165_B_3 Hunter UT 460 2 94 83,041,697 181

6166_B_MB1 Rockport IN 1,300 4 142 138,145,250 106 6166_B_MB2 Rockport IN 1,300 4 142 138,981,337 107

6170_B_1 Pleasant Prairie WI 617 3 72 55,255,225 90 6170_B_2 Pleasant Prairie WI 617 3 72 55,822,411 90

6177_B_U1B Coronado AZ 395 2 132 108,847,521 276 6177_B_U2B Coronado AZ 390 2 132 105,111,801 270

6178_B_1 Coleto Creek TX 632 4 26 21,145,534 33

66

6179_B_1 Fayette Power Project TX 598 5 98 65,108,619 109 6179_B_2 Fayette Power Project TX 598 5 98 64,482,723 108 6179_B_3 Fayette Power Project TX 445 4 64 44,478,896 100

6180_B_OG1 Oak Grove TX 800 6 190 85,241,342 107 6180_B_OG2 Oak Grove TX 800 6 190 85,241,342 107

6181_B_1 J T Deely TX 385 2 30 27,795,726 72 6181_B_2 J T Deely TX 385 2 30 27,756,673 72

6183_B_SM-1 San Miguel TX 391 3 62 45,994,741 118 6190_B_2 Rodemacher LA 523 2 27 25,318,899 48

6190_B_3A Rodemacher LA 330 1 5 5,011,157 15 6190_B_3B Rodemacher LA 330 1 5 5,011,157 15

6193_B_061B Harrington TX 347 4 42 22,996,183 66 6193_B_062B Harrington TX 347 4 42 24,424,959 70 6193_B_063B Harrington TX 347 4 42 24,863,255 72 6194_B_171B Tolk TX 535 2 24 21,681,861 41 6194_B_172B Tolk TX 545 2 24 21,315,741 39

6195_B_1 Southwest Power Station MO 178 3 224 115,261,948 648 6204_B_1 Laramie River Station WY 565 4 154 86,961,102 154 6204_B_2 Laramie River Station WY 570 4 154 83,331,016 146 6204_B_3 Laramie River Station WY 570 4 154 92,413,957 162

6213_B_1SG1 Merom IN 507 2 65 62,606,265 123 6213_B_2SG1 Merom IN 493 2 65 64,220,141 130

6225_B_1 Jasper 2 IN 14 1 3 866,561 62 6238_B_1A Pearl Station IL 22 1 6 2,112,513 96 6248_B_1 Pawnee CO 505 2 13 8,921,462 18 6249_B_1 Winyah SC 295 1 130 121,732,828 413 6249_B_2 Winyah SC 295 1 130 122,722,703 416 6249_B_3 Winyah SC 295 1 130 121,333,096 411 6249_B_4 Winyah SC 270 1 130 120,256,266 445

6250_B_1A Mayo NC 371 4 320 194,458,700 524

67

6250_B_1B Mayo NC 371 4 320 194,458,700 524 6254_B_1 Ottumwa IA 673 2 116 87,704,788 130 6257_B_1 Scherer GA 837 3 233 241,767,423 289 6257_B_2 Scherer GA 843 3 233 243,015,931 288 6257_B_3 Scherer GA 875 3 233 247,595,035 283 6257_B_4 Scherer GA 850 3 233 243,874,806 287 6264_B_1 Mountaineer WV 1,300 3 50 51,914,394 40

6469_B_B1 Antelope Valley ND 450 2 59 50,262,299 112 6469_B_B2 Antelope Valley ND 450 2 59 50,577,883 112

6481_B_1SGA Intermountain Power Project UT 900 3 233 158,299,880 176 6481_B_2SGA Intermountain Power Project UT 900 3 233 158,299,880 176

6639_B_G1 R D Green KY 231 2 8 5,747,905 25 6639_B_G2 R D Green KY 233 2 8 5,770,269 25 6641_B_1 Independence AR 836 4 47 37,254,469 45 6641_B_2 Independence AR 842 4 47 37,171,856 44 6648_B_4 Sandow TX 545 4 107 74,584,612 137

6664_B_101 Louisa IA 745 2 59 61,830,763 83 6705_B_1 Warrick IN 136 2 17 9,509,125 70 6705_B_2 Warrick IN 136 2 17 9,523,228 70 6705_B_3 Warrick IN 136 2 17 9,537,272 70 6705_B_4 Warrick IN 300 2 17 12,924,387 43

6761_B_101 Rawhide CO 272 2 18 12,342,549 45 6768_B_1 Sikeston Power Station MO 233 2 36 23,625,426 101 6772_B_1 Hugo OK 440 2 67 58,910,578 134

6823_B_W1 D B Wilson KY 420 2 49 36,972,967 88 7030_B_U1 Twin Oaks Power One TX 152 2 13 5,921,171 39 7030_B_U2 Twin Oaks Power One TX 153 2 13 6,858,395 45

7097_B_BLR1 J K Spruce TX 555 3 58 44,996,468 81 7097_B_BLR2 J K Spruce TX 750 3 58 48,312,157 64 7210_B_COP1 Cope SC 420 2 177 152,775,716 364

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7213_B_1 Clover VA 431 4 280 187,989,514 436 7213_B_2 Clover VA 434 5 431 217,508,623 501

7242_G_1CA Polk FL 123 1 1 689,955 6 7242_G_1CT Polk FL 132 1 1 708,828 5

7286_B_1 Richard Gorsuch OH 50 1 5 2,652,682 53 7286_B_2 Richard Gorsuch OH 50 1 5 2,652,682 53 7286_B_3 Richard Gorsuch OH 50 1 5 2,652,682 53 7286_B_4 Richard Gorsuch OH 50 1 5 2,652,682 53 7343_B_4 George Neal South IA 632 2 94 100,888,536 160 7504_B_2 Neil Simpson II WY 80 1 23 13,829,794 173

7537_B_1A North Branch WV 37 1 10 4,456,718 120 7537_B_1B North Branch WV 37 1 10 4,315,178 117 7549_B_1 Milwaukee County WI 3 1 5 1,001,342 303 7549_B_2 Milwaukee County WI 3 1 5 958,082 290 7549_B_3 Milwaukee County WI 3 1 5 958,082 290

7652_B_D-1 US DOE Savannah River Site (D Area) SC 20 1 30 10,455,104 533 7652_B_D-2 US DOE Savannah River Site (D Area) SC 20 1 30 10,455,104 533 7652_B_D-3 US DOE Savannah River Site (D Area) SC 20 1 30 10,455,104 533 7652_B_D-4 US DOE Savannah River Site (D Area) SC 20 1 30 10,455,104 533

7737_B_B001 Cogen South SC 90 1 82 50,925,685 566 7790_B_1-1 Bonanza UT 468 5 75 40,737,592 87 7902_B_1 Pirkey TX 675 2 4 4,246,866 6 8023_B_1 Columbia WI 555 4 306 219,530,738 396 8023_B_2 Columbia WI 559 4 306 214,992,053 385 8042_B_1 Belews Creek NC 1,115 3 122 76,553,763 69 8042_B_2 Belews Creek NC 1,115 3 122 76,537,100 69

8066_B_BW71 Jim Bridger WY 530 2 3 2,411,220 5 8066_B_BW72 Jim Bridger WY 530 2 3 2,418,842 5 8066_B_BW73 Jim Bridger WY 530 2 3 2,404,606 5 8066_B_BW74 Jim Bridger WY 530 2 3 2,417,759 5

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8069_B_1 Huntington UT 445 2 68 63,247,668 142 8069_B_2 Huntington UT 450 2 68 63,434,031 141 8102_B_1 General James M Gavin OH 1,310 3 52 49,730,161 38 8102_B_2 General James M Gavin OH 1,300 3 52 49,430,685 38 8219_B_1 Ray D Nixon CO 208 2 130 91,347,020 439

8222_B_B1 Coyote ND 427 2 59 50,345,130 118 8223_B_1 Springerville AZ 400 2 170 137,893,456 345 8223_B_2 Springerville AZ 400 2 170 137,336,825 343 8223_B_3 Springerville AZ 400 2 170 142,795,380 357 8223_B_4 Springerville AZ 400 2 170 131,249,797 328 8224_B_1 North Valmy NV 254 3 420 246,905,695 972 8224_B_2 North Valmy NV 268 3 420 262,664,147 980 8226_B_1 Cheswick PA 580 3 30 23,108,254 40

10002_B_CFB ACE Cogeneration Facility CA 101 1 55 36,115,023 357 10003_B_BLR3 Trigen Colorado Energy CO 8 1 17 4,224,070 521 10003_B_BLR4 Trigen Colorado Energy CO 8 1 17 4,224,070 521 10003_B_BLR5 Trigen Colorado Energy CO 8 1 17 4,462,765 551

10030_B_COGEN1 NRG Energy Center Dover DE 16 1 41 13,762,699 860 10043_B_B01 Logan Generating Plant NJ 219 3 7 3,257,942 15 10071_B_1A Cogentrix Virginia Leasing Corporation VA 19 1 53 18,675,110 973 10071_B_1B Cogentrix Virginia Leasing Corporation VA 19 1 53 17,966,383 936 10071_B_1C Cogentrix Virginia Leasing Corporation VA 19 1 53 17,966,383 936 10071_B_2A Cogentrix Virginia Leasing Corporation VA 19 1 53 18,675,110 973 10071_B_2B Cogentrix Virginia Leasing Corporation VA 19 1 53 17,966,383 936 10071_B_2C Cogentrix Virginia Leasing Corporation VA 19 1 53 17,966,383 936 10075_B_1 Taconite Harbor Energy Center MN 65 1 77 43,873,377 675 10075_B_2 Taconite Harbor Energy Center MN 67 1 77 44,056,543 658 10075_B_3 Taconite Harbor Energy Center MN 68 1 77 44,508,992 655

10113_B_CFB1 John B Rich Memorial Power Station PA 40 1 22 10,166,547 254 10113_B_CFB2 John B Rich Memorial Power Station PA 40 1 22 9,865,959 247

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10143_B_ABB01 Colver Power Project PA 110 2 16 7,296,841 66 10151_B_BLR1A Grant Town Power Plant WV 40 1 14 6,230,377 156 10151_B_BLR1B Grant Town Power Plant WV 40 1 14 6,068,111 152

10207_B_1 Hercules Missouri Chemical Works MO 6 1 3 668,369 117 10207_B_2 Hercules Missouri Chemical Works MO 6 1 3 668,369 117 10207_B_3 Hercules Missouri Chemical Works MO 6 1 3 668,369 117 10333_B_1 Central Power & Lime FL 139 1 5 3,407,144 25

10343_B_SG-101 Foster Wheeler Mt Carmel Cogen PA 43 1 22 10,975,235 255 10367_B_CB1302 East Third Street Power Plant CA 20 1 4 1,397,893 72 10368_B_CB1302 Loveridge Road Power Plant CA 19 1 3 1,250,255 66 10369_B_CB1302 Wilbur West Power Plant CA 19 1 2 644,904 34 10370_B_CB1302 Wilbur East Power Plant CA 19 1 3 1,043,072 55 10371_B_CB1302 Nichols Road Power Plant CA 19 1 3 1,298,925 68 10373_B_CB1302 Hanford CA 25 1 22 8,730,145 352

10377_B_1A Cogentrix Hopewell VA 18 1 10 3,417,788 188 10377_B_1B Cogentrix Hopewell VA 18 1 10 3,531,133 194 10377_B_1C Cogentrix Hopewell VA 18 1 10 3,417,788 188 10377_B_2A Cogentrix Hopewell VA 18 1 10 3,531,133 194 10377_B_2B Cogentrix Hopewell VA 18 1 10 3,417,788 188 10377_B_2C Cogentrix Hopewell VA 18 1 10 3,417,788 188 10378_B_1A Primary Energy Southport NC 18 1 173 59,585,090 3,347 10378_B_1B Primary Energy Southport NC 18 1 173 57,630,632 3,238 10378_B_1C Primary Energy Southport NC 18 1 173 57,630,632 3,238 10378_B_2A Primary Energy Southport NC 18 1 173 59,585,090 3,347 10378_B_2B Primary Energy Southport NC 18 1 173 57,630,632 3,238 10378_B_2C Primary Energy Southport NC 18 1 173 57,630,632 3,238 10379_B_1A Primary Energy Roxboro NC 19 1 24 8,355,164 447 10379_B_1B Primary Energy Roxboro NC 19 1 24 8,092,596 433 10379_B_1C Primary Energy Roxboro NC 19 1 24 8,092,596 433

10380_B_A BLR Elizabethtown Power LLC NC 16 1 129 42,742,982 2,671

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10380_B_B BLR Elizabethtown Power LLC NC 16 1 129 42,742,982 2,671 10382_B_UNIT1 Lumberton NC 16 1 118 39,366,830 2,460 10382_B_UNIT2 Lumberton NC 16 1 118 39,366,830 2,460

10384_B_1A Edgecombe GenCo NC 29 1 36 14,989,978 519 10384_B_1B Edgecombe GenCo NC 29 1 36 14,534,809 503 10384_B_2A Edgecombe GenCo NC 29 1 36 14,989,978 519 10384_B_2B Edgecombe GenCo NC 29 1 36 14,534,809 503

10464_B_E0001 Black River Generation NY 18 1 27 9,340,465 510 10464_B_E0002 Black River Generation NY 18 1 27 8,971,022 490 10464_B_E0003 Black River Generation NY 18 1 27 8,971,022 490

10477_B_P1 Wisconsin Rapids Pulp Mill WI 11 1 80 22,287,032 1,990 10477_B_P2 Wisconsin Rapids Pulp Mill WI 11 1 80 22,287,032 1,990 10495_B_6 Rumford Cogeneration ME 43 1 24 11,293,272 266 10495_B_7 Rumford Cogeneration ME 43 1 24 10,978,023 258

10566_B_BOIL1 Chambers Cogeneration LP NJ 131 2 17 9,093,687 69 10566_B_BOIL2 Chambers Cogeneration LP NJ 131 2 17 9,238,900 71 10601_G_GEN1 BP Wilmington Calciner CA 29 1 3 1,039,284 36

10603_B_031 Ebensburg Power PA 50 1 4 2,168,090 44 10641_B_B1 Cambria Cogen PA 44 1 3 1,426,559 32 10641_B_B2 Cambria Cogen PA 44 1 3 1,388,167 32

10670_B_AAB001 AES Deepwater TX 140 2 0 184,032 1 10671_B_1A AES Shady Point OK 80 1 3 1,973,180 25 10671_B_1B AES Shady Point OK 80 1 3 1,965,567 25 10671_B_2A AES Shady Point OK 80 1 3 1,973,180 25 10671_B_2B AES Shady Point OK 80 1 3 1,965,567 25

10672_B_CBA Cedar Bay Generating LP FL 83 1 20 11,321,540 136 10672_B_CBB Cedar Bay Generating LP FL 83 1 20 11,679,195 140 10672_B_CBC Cedar Bay Generating LP FL 83 1 20 11,679,195 140

10675_B_A AES Thames CT 91 1 26 15,600,819 172 10675_B_B AES Thames CT 91 1 26 15,682,088 173

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10676_B_2 AES Beaver Valley Partners Beaver V ll

PA 43 1 4 2,100,058 49 10676_B_3 AES Beaver Valley Partners Beaver

V llPA 43 1 4 2,159,729 50

10676_B_4 AES Beaver Valley Partners Beaver V ll

PA 43 1 4 2,159,729 50 10676_B_5 AES Beaver Valley Partners Beaver

V llPA 17 1 4 1,520,200 89

10678_B_BLR1 AES Warrior Run Cogeneration Facility MD 180 1 13 10,326,468 57 10684_B_BLR25 Argus Cogen Plant CA 25 1 55 20,748,431 830 10684_B_BLR26 Argus Cogen Plant CA 25 1 55 20,748,431 830 10743_B_CFB1 Morgantown Energy Facility WV 25 1 12 4,578,240 183 10743_B_CFB2 Morgantown Energy Facility WV 25 1 12 4,417,517 177 10768_B_CFB Rio Bravo Jasmin CA 33 1 29 12,560,352 381 10769_B_CFB Rio Bravo Poso CA 33 1 9 4,078,042 124

10771_B_1 Hopewell VA 32 1 10 4,433,144 141 10771_B_2 Hopewell VA 32 1 10 4,433,144 141 10773_B_1 Altavista Power Station VA 32 1 7 3,025,687 96 10773_B_2 Altavista Power Station VA 32 1 7 3,025,687 96 10774_B_1 Southampton Power Station VA 63 1 21 11,523,948 183 10774_B_2 Southampton Power Station VA 37 1 21 9,507,426 260

10784_B_BLR1 Colstrip Energy LP MT 35 1 136 60,677,814 1,734 10849_B_BLR1 Silver Bay Power MN 36 1 53 23,127,868 642 10849_B_BLR2 Silver Bay Power MN 69 1 53 29,467,498 427 50012_B_BLR4 Alloy Steam Station WV 38 1 16 6,888,251 181

50030_B_1A Nelson Industrial Steam and Operating C

LA 107 2 7 2,705,642 25 50030_B_2A Nelson Industrial Steam and Operating

CLA 106 2 7 2,679,457 25

50039_B_1 Kline Township Cogen Facility PA 50 1 27 13,837,247 277 50130_B_BLR1 G F Weaton Power Station PA 56 1 3 1,630,715 29 50130_B_BLR2 G F Weaton Power Station PA 56 1 3 1,630,715 29

50202_B_1 WPS Power Niagara NY 53 1 3 1,434,035 27 50368_G_TG1 Cornell University Central Heat NY 1 1 3 268,863 269 50368_G_TG2 Cornell University Central Heat NY 5 1 3 542,420 102 50388_B_K1 Phillips 66 Carbon Plant CA 10 1 1 197,169 20

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50388_B_K2 Phillips 66 Carbon Plant CA 10 1 1 197,169 20 50397_B_1PB035 P H Glatfelter PA 9 1 7 1,841,605 212 50397_B_3PB033 P H Glatfelter PA 4 1 7 1,493,030 373 50397_B_4PB034 P H Glatfelter PA 9 1 7 1,874,010 208 50397_B_5PB036 P H Glatfelter PA 36 1 7 3,138,015 87

50410_B_10 Chester Operations PA 36 1 0 165,409 5 50611_B_031 WPS Westwood Generation LLC PA 30 1 9 3,969,914 132

50651_B_1 Trigen Syracuse Energy NY 11 1 8 2,211,538 199 50651_B_2 Trigen Syracuse Energy NY 11 1 8 2,243,056 202 50651_B_3 Trigen Syracuse Energy NY 11 1 8 2,243,056 202 50651_B_4 Trigen Syracuse Energy NY 11 1 8 2,243,056 202 50651_B_5 Trigen Syracuse Energy NY 11 1 8 2,243,056 202

50651_G_GEN2 Trigen Syracuse Energy NY 11 1 8 2,211,538 201 50776_B_BLR1 Panther Creek Energy Facility PA 42 1 22 10,108,238 244 50776_B_BLR2 Panther Creek Energy Facility PA 42 1 22 10,224,344 246 50806_B_PB4 Stone Container Florence Mill SC 75 1 122 69,382,961 928

50835_B_1 TES Filer City Station MI 30 1 42 17,747,919 592 50835_B_2 TES Filer City Station MI 30 1 42 17,141,107 571

50879_B_BLR1 Wheelabrator Frackville Energy PA 45 1 21 10,414,793 234 50888_B_BLR1 Northampton Generating Company PA 112 1 5 3,307,302 30 50931_B_BLR1 Yellowstone Energy LP MT 28 1 149 65,987,299 2,400 50931_B_BLR2 Yellowstone Energy LP MT 28 1 149 58,025,007 2,110

50951_B_1 Sunnyside Cogen Associates UT 51 1 15 7,903,915 155 50974_B_UNIT 1 Scrubgrass Generating PA 43 1 8 3,993,426 94 50974_B_UNIT 2 Scrubgrass Generating PA 43 1 8 3,881,950 91 50976_B_AAB01 Indiantown Cogeneration LP FL 330 2 4 3,323,473 10 52007_B_BLR1 Mecklenburg Power Station VA 69 1 15 8,567,737 124 52007_B_BLR2 Mecklenburg Power Station VA 69 1 15 8,567,737 124

52071_B_5A Sandow 5 TX 300 2 32 23,260,335 78 52071_B_5B Sandow 5 TX 300 2 32 23,260,335 78

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54035_B_BLR1 Westmoreland Roanoke Valley I NC 165 2 62 36,771,503 223 54081_B_1A Cogentrix of Richmond VA 26 1 8 3,050,662 116 54081_B_1B Cogentrix of Richmond VA 26 1 8 2,948,358 112 54081_B_2A Cogentrix of Richmond VA 26 1 8 3,050,662 116 54081_B_2B Cogentrix of Richmond VA 26 1 8 2,948,358 112 54081_B_3A Cogentrix of Richmond VA 21 1 8 2,820,983 132 54081_B_3B Cogentrix of Richmond VA 21 1 8 2,723,771 128 54081_B_4A Cogentrix of Richmond VA 21 1 8 2,820,983 132 54081_B_4B Cogentrix of Richmond VA 21 1 8 2,723,771 128

54144_B_BRBR1 Piney Creek Project PA 33 1 16 6,808,383 209 54224_B_GEN6 Franklin Heating Station MN 3 1 43 7,175,049 2,563

54238_B_N64514 Port of Stockton District Energy Fac CA 22 1 3 997,963 45 54238_B_N64516 Port of Stockton District Energy Fac CA 22 1 3 958,629 44

54304_B_1A Birchwood Power VA 239 1 29 25,665,810 107 54406_G_1 Capitol Heat and Power WI 1 1 28 2,967,700 3,297 54406_G_2 Capitol Heat and Power WI 1 1 28 2,967,700 2,968

54626_B_BL01 Mt Poso Cogeneration CA 52 1 18 9,385,483 180 54634_B_1 St Nicholas Cogen Project PA 88 1 24 14,921,531 170

54677_B_HRB CII Carbon LLC LA 23 1 1 409,816 18 54677_G_TG-2 CII Carbon LLC LA 23 1 1 409,816 18 54755_B_BLR2 Westmoreland Roanoke Valley II NC 44 1 9 4,516,042 103

54775_B_BLR10 University of Iowa Main Power Plant IA 4 1 12 2,476,778 590 54775_B_BLR11 University of Iowa Main Power Plant IA 4 1 12 2,476,778 590

54992_G_ST Fellsway Development LLC MA 0 1 4 345,520 1,728 55076_B_AA001 Red Hills Generating Facility MS 220 1 6 5,085,298 23 55076_B_AA002 Red Hills Generating Facility MS 220 1 6 5,209,367 24

55360_B_1 Two Elk Generating Station WY 300 2 88 32,932,652 110 55479_B_3 Wygen 1 WY 70 1 22 12,384,742 177

55749_B_PC1 Hardin Generator Project MT 109 1 113 76,683,994 706 55856_B_PC1 Prairie State Generating Company LLC IL 800 3 102 75,746,741 95

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55856_B_PC2 Prairie State Generating Company LLC IL 800 3 102 75,746,741 95 56037_G_1 Fox Valley Energy Center WI 7 1 12 2,829,794 435 56068_B_1 Elm Road Generating Station WI 617 3 87 69,303,550 112 56068_B_2 Elm Road Generating Station WI 617 3 87 69,303,550 112 56163_B_1 KUCC UT 30 1 5 2,097,370 70 56163_B_2 KUCC UT 30 1 5 2,097,370 70 56163_B_3 KUCC UT 30 1 5 2,097,370 70 56163_B_4 KUCC UT 65 1 5 2,599,586 40

56224_B_001 TS Power Plant NV 200 2 279 166,191,132 831 56319_B_4 Wygen WY 90 1 22 12,811,795 142 56319_B_5 Wygen WY 100 1 22 13,317,187 133

56456_B_STG1 Plum Point Energy AR 665 2 34 33,548,267 50 56671_B_1 Longview Power WV 695 2 21 21,085,857 30 82794_C_1 ERCT_TX_Coal steam TX 300 2 8 3,520,181 12 82821_B_1 Great River Energy Spiritwood Station ND 99 1 14 8,403,970 85 82886_C_1 NWPE_WY_Coal steam WY 422 3 212 111,573,136 264 82909_C_1 RFCO_IN_IGCC IN 630 3 69 56,903,399 90 82916_C_1 RMPA_CO_Coal steam CO 18 1 11 3,744,305 208 82932_C_1 SPPN_KS_Coal steam KS 22 1 10 3,755,430 171 82934_C_1 SPPN_MO_Coal steam MO 1,150 3 82 79,762,328 69

82998_B_CFB1 Virginia City Hybrid Energy Center VA 293 3 168 99,750,208 341 82998_B_CFB2 Virginia City Hybrid Energy Center VA 293 3 168 99,750,208 341

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● ● ● 5.4.3 Mercury Control Capabilities EPA Base Case v4.10_PTox offers two options for meeting mercury reduction requirements: (1) combinations of SO2, NOX, and particulate controls which deliver mercury reductions as a co-benefit and (2) Activated Carbon Injection (ACI), a retrofit option specifically designed for mercury control. These two options are discussed below. Mercury Control through SO2 and NOX Retrofits In EPA Base Case v4.10, units that install SO2, NOX, and particulate controls, reduce mercury emissions as a byproduct of these retrofits. Section 5.4.2 described how EMFs are used in the base case to capture the unregulated mercury emissions depending on the rank of coal burned, the generating unit’s combustion characteristics, and the specific configuration of SO2, NOX, and particulate controls (i.e., hot and cold-side electrostatic precipitators (ESPs), fabric filters (also called “baghouses”) and particulate matter (PM) scrubbers). These same EMFs would be available in mercury policy runs to characterize the mercury reductions that can be achieved by retrofitting a unit with SCR, SO2 scrubbers and particulate controls. The absence of a federal mercury emission reduction policy means that these controls appear in the base case in response to SO2, NOX, or particulate limits or state-level mercury emission requirements. However, in future model runs where mercury limits are present these same SO2 and NOX controls could be deliberately installed for mercury control if they provide the least cost option for meeting mercury policy limits. Activated Carbon Injection (ACI) The technology specifically designated for mercury control is Activated Carbon Injection (ACI) downstream of the combustion process in coal fired units. In preparation for performing modeling of air toxics, a comprehensive update of ACI cost and performance assumptions was undertaken by Sargent & Lundy, the same engineering firm that developed the SO2 and NOX control assumptions used in EPA Base Case v4.10. The ACI update, whose elements are described below, incorporates the latest field experience through 2010. Assuming a target of 90% removal from the level of mercury in the coal, three alternative ACI options were identified as providing the required rate of removal for all possible configurations of boiler, emission controls, and coal types used in the U.S. electric power sector. The three ACI options differed based on the type of particulate control device − electrostatic precipitator (ESP) or pre-existing or new fabric filter (also called a “baghouse”), i.e.,

• ACI with Existing ESP • ACI with Existing Baghouse • ACI with an Additional Full Baghouse (also referred to as Toxecon)

All three configurations assume the use of brominated ACI, where a small amount of bromine is chemically bonded to the powdered carbon which is injected into the flue gas stream. The use of brominated ACI exploits the discovery that by converting elemental mercury to oxidized mercury, halogens (like chlorine, iodine, and bromine) can make activated carbon more effective in capturing the mercury at the high temperatures found in industrial processes like power generation. The ionic mercury adheres to the activated carbon (and to fly ash and unburned carbon in the fuel gas) which can be removed efficiently from the flue gas by the

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particulate control device (ESP or fabric filter). In the third option listed above the additional baghouse is installed downstream of the pre-existing particulate matter device and the activated carbon is injected after the existing controls. This configuration allows the fly ash to be removed before the mercury controls to preserve its marketability. The applicable ACI option depends on the coal type burned, its SO2 content, the boiler and particulate control type and, in some instances, consideration of whether an SO2 scrubber (FGD) system and SCR NOx post-combustion control are present. Table 5-16 shows the ACI assignment scheme used in EPA Base Case v4.10_PTox to achieve 90% mercury removal.

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Table 5-16. Assignment Scheme for Mercury Emissions Control Using Activated Carbon Injection (ACI) in EPA Base Case v4.10_PTox (Proposed Toxics Rule).

Air pollution controls Bituminous Coal Subbituminous Coal Lignite Coal

Burner Type Particulate Control Type SCR System

FGD System

ACI Required?

Toxecon Required?

Sorbent Inj Rate

(lb/million acf)

ACI Required?

Toxecon Required?

Sorbent Inj Rate

(lb/million acf)

ACI Required?

Toxecon Required?

Sorbent Inj Rate

(lb/million acf)

FBC Cold Side ESP + Fabric Filter without FGC -- -- Yes No 2 Yes No 2 Yes No 2

FBC Cold Side ESP without FGC -- -- Yes No 5 Yes No 5 Yes No 5

FBC Fabric Filter -- Dry FGD No No 0 Yes No 2 Yes No 2

FBC Fabric Filter -- -- Yes No 2 Yes No 2 Yes No 2

FBC Hot Side ESP with FGC -- -- Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC Cold Side ESP + Fabric Filter with FGC -- Dry FGD Yes No 2 Yes No 2 Yes No 2

Non-FBC Cold Side ESP + Fabric Filter with FGC -- -- Yes No 2 Yes No 2 Yes No 2

Non-FBC Cold Side ESP + Fabric Filter with FGC -- Wet FGD Yes No 2 Yes No 2 Yes No 2

Non-FBC Cold Side ESP + Fabric Filter with FGC SCR -- Yes No 2 Yes No 2 Yes No 2

Non-FBC Cold Side ESP + Fabric Filter with FGC SCR Dry FGD Yes No 2 Yes No 2 Yes No 2

Non-FBC Cold Side ESP + Fabric Filter with FGC SCR Wet FGD Yes No 2 Yes No 2 Yes No 2

Non-FBC Cold Side ESP + Fabric Filter without FGC -- Dry FGD Yes No 2 Yes No 2 Yes No 2

Non-FBC Cold Side ESP + Fabric Filter without FGC -- -- Yes No 2 Yes No 2 Yes No 2

Non-FBC Cold Side ESP + Fabric Filter without FGC -- Wet FGD Yes No 2 Yes No 2 Yes No 2

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Non-FBC Cold Side ESP + Fabric Filter without FGC SCR -- Yes No 2 Yes No 2 Yes No 2

Non-FBC Cold Side ESP + Fabric Filter without FGC SCR Dry FGD Yes No 2 Yes No 2 Yes No 2

Non-FBC Cold Side ESP + Fabric Filter without FGC SCR Wet FGD Yes No 2 Yes No 2 Yes No 2

Non-FBC Cold Side ESP with FGC -- Dry FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC Cold Side ESP with FGC -- -- Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC Cold Side ESP with FGC -- Wet FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC Cold Side ESP with FGC SCR -- Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC Cold Side ESP with FGC SCR Dry FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC Cold Side ESP with FGC SCR Wet FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC Cold Side ESP without FGC -- Dry FGD Yes No 5 Yes No 5 Yes No 5

Non-FBC Cold Side ESP without FGC -- -- Yes No 5 Yes No 5 Yes No 5

Non-FBC Cold Side ESP without FGC -- Wet FGD Yes No 5 Yes No 5 Yes No 5

Non-FBC Cold Side ESP without FGC SCR -- Yes No 5 Yes No 5 Yes No 5

Non-FBC Cold Side ESP without FGC SCR Dry FGD Yes No 5 Yes No 5 Yes No 5

Non-FBC Cold Side ESP without FGC SCR Wet FGD Yes No 5 Yes No 5 Yes No 5

Non-FBC Fabric Filter -- Dry FGD Yes No 2 Yes No 2 Yes No 2

Non-FBC Fabric Filter -- -- Yes No 2 Yes No 2 Yes No 2

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Non-FBC Fabric Filter -- Wet FGD Yes No 2 Yes No 2 Yes No 2

Non-FBC Fabric Filter SCR Dry FGD Yes No 2 Yes No 2 Yes No 2

Non-FBC Fabric Filter SCR -- Yes No 2 Yes No 2 Yes No 2

Non-FBC Fabric Filter SCR Wet FGD Yes No 2 Yes No 2 Yes No 2

Non-FBC Hot Side ESP + Fabric Filter with FGC -- -- Yes No 2 Yes No 2 Yes No 2

Non-FBC Hot Side ESP + Fabric Filter with FGC -- Wet FGD Yes No 2 Yes No 2 Yes No 2

Non-FBC Hot Side ESP + Fabric Filter with FGC -- Dry FGD No No 0 Yes No 2 Y(b) No 2

Non-FBC Hot Side ESP + Fabric Filter with FGC SCR Wet FGD Yes No 2 Yes No 2 Yes No 2

Non-FBC Hot Side ESP + Fabric Filter with FGC SCR Dry FGD No No 0 Yes No 2 Y(b) No 2

Non-FBC Hot Side ESP + Fabric Filter with FGC SCR -- Yes No 2 Yes No 2 Y(b) No 2

Non-FBC Hot Side ESP + Fabric Filter without FGC -- Dry FGD No No 0 Yes No 2 Yes No 2

Non-FBC Hot Side ESP + Fabric Filter without FGC -- -- Yes No 2 Yes No 2 Yes No 2

Non-FBC Hot Side ESP + Fabric Filter without FGC -- Wet FGD Yes No 2 Yes No 2 Yes No 2

Non-FBC Hot Side ESP + Fabric Filter without FGC SCR Dry FGD No No 0 Yes No 2 Yes No 2

Non-FBC Hot Side ESP + Fabric Filter without FGC SCR -- Yes No 2 Yes No 2 Yes No 2

Non-FBC Hot Side ESP + Fabric Filter without FGC SCR Wet FGD Yes No 2 Yes No 2 Yes No 2

Non-FBC Hot Side ESP with FGC -- Dry FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

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Non-FBC Hot Side ESP with FGC -- -- Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC Hot Side ESP with FGC -- Wet FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC Hot Side ESP with FGC SCR Dry FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC Hot Side ESP with FGC SCR -- Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC Hot Side ESP with FGC SCR Wet FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC Hot Side ESP without FGC -- Dry FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC Hot Side ESP without FGC -- -- Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC Hot Side ESP without FGC -- Wet FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC Hot Side ESP without FGC SCR Dry FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC Hot Side ESP without FGC SCR -- Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC Hot Side ESP without FGC SCR Wet FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC No Control -- Dry FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC No Control -- -- Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC No Control -- Wet FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC No Control SCR Dry FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC No Control SCR -- Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC No Control SCR Wet FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

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Non-FBC PM Scrubber -- Dry FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC PM Scrubber -- -- Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC PM Scrubber -- Wet FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC PM Scrubber SCR Dry FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC PM Scrubber SCR -- Yes Yes 2 Yes Yes 2 Yes Yes 2

Non-FBC PM Scrubber SCR Wet FGD Yes Yes 2 Yes Yes 2 Yes Yes 2

Note: In the table above "Toxecon" refers to the option described as "ACI System with an Additional Baghouse" and "ACI + Full Baghouse with a Sorbent Injection Rate of 2 lbs/million acfm" elsewhere in this chapter.

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Methodology for Obtaining ACI Control Costs: For ACI systems the carbon feed rate dictates the size of the equipment and resulting costs. The feed rate in turn is a function of the required removal (in this case 90%) and the type of particulate control device. Engineering experience had established that a carbon feed rate of 5 pounds of carbon injected for every 1,000,000 actual cubic feet per minute (acfm) of flue gas would provide the stipulated 90% mercury removal rate for units shown in Table 5-16 as qualifying for ACI systems with existing ESP. For generating units with fabric filters a 2 pound per million acfm is required. Alternative sets of costs were developed for each of the three ACI options: ACI systems for units with existing ESPs, ACI for units with existing fabric filters (baghouses), and the combined cost of ACI plus an additional baghouse for units that either have no existing particulate control or that require ACI plus a baghouse in addition to their existing particulate control. There are various reasons that a combined ACI plus additional baghouse would be required. These include situations where the existing ESP cannot handle the additional particulate load associate with the ACI or where SO3 injection is currently in use to condition the flue gas for the ESP. Another cause for combined ACI and baghouse is use of PRB coal whose combustion produces mostly elemental mercury, not ionic mercury, due to this coal’s low chlorine content. Capital Cost: Included in the installed capital cost of ACI are

• All equipment • Installation • Buildings • Foundations • Electrical

If an additional baghouse is required in combination with the ACI, specific installed capital costs include

• Duct work • Foundations • Structural steel • Induced draft (ID) fan modifications or new booster fans • Electrical modifications

For the combined ACI and fabric filter option a full size baghouse with an air-to-cloth (A/C) ratio of 4.0 is assumed, not a polishing baghouse with a 6.0 A/C ratio5. Table 5-17 shows the capital cost modules and the governing variables for ACI systems.

5 The “air-to-cloth” (A/C) ratio is the volumetric flow, (typically expressed in Actual Cubic Feet per Minute, ACFM) of flue gas entering the baghouse divided by the areas (typically in square feet) of fabric filter cloth in the baghouse. The lower the A/C ratio, e.g., A/C = 4.0 compared to A/C = 6.0, the greater area of the cloth required and the higher the cost for a given volumetric flow.

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Table 5‐17. Capital Cost Components and Their Governing Variables for ACI Systems

Module

Hg Removal Rate

Retrofit Difficulty

(1 = average)

ParticulateCapture Type (ESP or

Baghouse) Heat Rate(Btu/kWh)

Unit Size (MW)

Coal Type

ACI Injection ‐Carbon Feed Rate

X X X X X

Additional Fabric Filter (if needed)

X X X X

A bare installed total cost is calculated from the carbon feed rate based on the required removal rate, the particulate control, and the flue gas flow rate. The resulting bare installed total cost is increased by 15% to account for additional engineering and construction management costs, labor premiums, and contractor profits and fees. The resulting value is the capital, engineering, and construction cost (CECC) subtotal. To obtain the total project cost (TPC), the CECC subtotal is increased by 5% to account for owner’s home office costs, i.e., owner’s engineering, management, and procurement costs. Since ACI systems are expected to be completed in less than a year, no Allowance for Funds used During Construction (AFUDC) is provided for ACI systems by themselves. However, if combined with an additional baghouse, 6% is added to account for Allowance for Funds used During Construction (AFUDC) which is premised on a 2-year project duration for the baghouse.

The cost resulting from these calculations is the capital cost factor (expressed in $/kW) that is used in EPA Base Case v4.10_PTox. Variable Operating and Maintenance Costs (VOM): These are the costs incurred in running an emission control device. They are proportional to the electrical energy produced and are expressed in units of $ per MWh. For ACI, Sargent & Lundy identified three components of VOM: (a) reagent use and unit costs, (b) waste production and disposal cost, (c) cost of additional power required to run the DSI control (often called the “parasitic load”). For the ACI in combination with fabric filter option, the VOM includes a fourth component: (d) the cost of filter bag and cage replacement. (With an assumption that the A/C ratio = 6.0, the bag and cage replacement cycles are 3 and 9 years respectively.) For ACI carbon usage is a function of unit size and heat rate. The carbon waste production is equal to the carbon feed rate. To provide a conservative estimate, the costing analysis assumed that the carbon is captured in the same particulate collector as the fly ash, making it

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necessary for both the total fly ash and the carbon to be landfilled. Typical ash contents for each fuel were used to calculate a total fly ash production rate. For purposes of modeling, the total VOM includes cost components (a), (b), and, where applicable, (d) as noted above. Component (c) – cost of additional power for the ACI system – is factored into IPM, not in the VOM value, but through capacity and heat rate penalties as described in the next paragraph. Capacity and Heat Rate Penalty: The amount of electrical power required to operate the ACI system is represented through a reduction in the amount of electricity that is available for sale to the grid. For example in the option of a combined ACI system with an additional baghouse, if 0.65% of the unit’s electrical generation is needed to operate the combined system, the generating unit’s capacity is reduced by 0.65%. This is the “capacity penalty.” At the same time, to capture the total fuel used in generation both for sale to the grid and for internal load (i.e., for operating the ACI device), the unit’s heat rate is scaled up such that a comparable reduction (0.65% in the previous example) in the new higher heat rate yields the original heat rate. The factor used to scale up the original heat rate is called “heat rate penalty.” It is a modeling procedure only and does not represent an increase in the unit’s actual heat rate (i.e., a decrease in the unit’s generation efficiency). As was the case for FGD in EPA Base Case v4.10, specific ACI heat rate and capacity penalties are calculated for each installation. For ACI, the site specific calculations take into account the additional power required for blowers for the injection system and, where an additional fabric filter is present, the power for the baghouse compressors. Fixed Operating and Maintenance Costs (FOM): These are the annual costs of maintaining a unit. They represent expenses incurred regardless of the extent to which the emission control system is run. They are expressed in units of $ per kW per year. In calculating FOM Sargent & Lundy took into account labor and materials costs associated with operations, maintenance, and administrative functions. The following assumptions were made:

• FOM for operations is based on the number of addition operators needed. For ACI one (1) additional operator is assumed to be needed. • FOM for maintenance is a direct function of the ACI capital cost. • FOM for administration is a function of the FOM for operations and maintenance.

Table 5-18 presents the capital, VOM, and FOM costs as well as the capacity and heat rate penalties for the three ACI options represented in EPA Base Case v4.10_PTox (Proposed Toxics Rule). For each ACI option values are shown for an illustrative set of generating units with a representative range of capacities and heat rates. Tables 1-3 in Appendix 5-3 contains illustration worksheets of the detailed calculations performed to obtain the capital, VOM, and FOM costs for examples of the three ACI options described in this section. The worksheets were developed by Sargent & Lundy6.

6 These worksheets were extracted from Sargent & Lundy LLC, IPM Model – Revisions to Cost and Performance for APC Technologies: Mercury Control Cost Development Methodology (Project 12301-009), October 2010. The complete report is available for review and downloading at www.epa.gov/airmarkets/progsregs/epa-ipm/.

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Table 5-18. Illustrative Activated Carbon Injection (ACI) Costs for Representative Sizes and Heat Rates Under Assumptions in EPA Base Case v4.10_PTox (Proposed Toxics Rule)

Control Type Heat Rate (Btu/kWh)

Capacity Penalty

(%) Heat Rate

Penalty (%) Variable O&M

(mills/kWh)

Capacity (MW)

100 300 500 700 1000

Capital Cost

($/kW)

Fixed O&M

($/kW-yr)

Capital Cost

($/kW)

Fixed O&M

($/kW-yr)

Capital Cost

($/kW)

Fixed O&M

($/kW-yr)

Capital Cost

($/kW)

Fixed O&M

($/kW-yr)

Capital Cost

($/kW)

Fixed O&M

($/kW-yr)

ACI System with an

Existing ESP

ACI with a Sorbent

Injection Rate of 5 lbs/million

acfm Assuming

Bituminous Coal

9,000

10,000

11,000

0.12

0.13

0.14

0.12

0.13

0.14

2.76

3.07

3.38

32.06

32.56

33.04

0.13

0.14

0.14

12.60

12.80

12.99

0.05

0.05

0.05

8.16

8.29

8.41

0.03

0.03

0.04

6.13

6.23

6.32

0.03

0.03

0.03

4.53

4.60

4.67

0.02

0.02

0.02

ACI System with an Existing Baghouse ACI with a Sorbent Injection Rate of 2 lbs/million acfm Assuming Bituminous Coal

9,000

10,000

11,000

0.05

0.05

0.06

0.05

0.05

0.06

2.24

2.49

2.74

27.93

28.37

28.80

0.12

0.12

0.12

10.98

11.16

11.32

0.05

0.05

0.05

7.11

7.23

7.33

0.03

0.03

0.03

5.34

5.43

5.51

0.02

0.02

0.02

3.95

4.01

4.07

0.02

0.02

0.02

ACI System with an Additional Baghouse ACI + Full Baghouse with a Sorbent Injection Rate of 2 lbs/million acfm Assuming Bituminous Coal

9,000

10,000

11,000

0.65

0.65

0.66

0.65

0.66

0.66

0.50

0.54

0.58

240

259

278

0.91

0.98

1.05

182

197

212

0.69

0.75

0.80

162

176

189

0.61

0.67

0.72

150

163

176

0.57

0.62

0.67

139

151

163

0.53

0.57

0.62

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5.5 Hydrogen Chloride (HCl) Control Technologies Consistent with other analysis performed for the Toxics Rule, hydrogen chloride (HCl) is used in EPA Base Case v4.10_PTox (Proposed Toxics Rule) as a surrogate for the acid gas hazardous air pollutants (HAPs). (See Toxics Rule preamble for a discussion of this topic.) The following sections describe how HCl emissions from coal are represented in IPM, the emission control technologies available for HCl removal, and the cost and performance characteristics of these technologies. 5.5.1 Chlorine Content of Fuels HCl emissions from the power sector result from the chlorine content of the coal that is combusted by electric generating units. Data on chlorine content of coals had been collected as part EPA’s 1999 “Information Collection Request for Electric Utility Steam Generating Unit Mercury Emissions Information Collection Effort” (ICR 1999) described above in section 5.4.1 To provide the capability for EPA Base Case v4.10 to account for HCl emissions, this data had to be incorporated into the model. The procedures used for this are presented in the updated text in section 9.1.3 below. 5.5.2 HCl Removal Rate Assumptions for Existing and Potential Units SO2 emission controls on existing and new (potential) units provide the HCl reductions indicated in Table 5-19. New supercritical pulverized coal units (column 3) that the model builds include FGD (wet or dry) which is assumed to provide a 99% removal rates for HCl. For existing conventional pulverized coal units with pre-existing FGD (column 5), the HCl removal rate is 5% higher than the reported SO2 removal rate up to a maximum of 99% removal. In addition, for fluidized bed combustion units (column 4) with no FGD and no fabric filter, the HCl removal rate is the same as the SO2 removal rate up to a maximum of 95%. FBCs with fabric filters have an HCl removal rate of 95%. When policies for controlling toxics emissions are modeled, it is assumed prior to performing a model run that the most cost effective default option for existing coal steam units with FGD would be to upgrade their FGDs to obtain at least 90% SO2 removal and 99% HCl removal and then let the model determine if any further reductions are needed. The cost of the FGD Upgrade Adjustment, as it is called, is assumed to be $100/kW (in 2009$). It is applied in the model as an FOM cost adder7.

7 The FGD Upgrade Adjustment is applied in the model as a FOM cost adder, where

FOM Adder = FGD Upgrade Adjustment X Capital Charge Rate = $100/kW ($2009) X 11.3% = $11.30/kW-yr ($2009)

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Table 5‐19. HCl Removal Rate Assumptions for Potential (New) and Existing Units in EPA Base Case v4.10_PTox (Proposed Toxics Rule)

Potential (New)

Existing Units with FGD Base Case Policy Case

Gas

Controls ==>

Supercritical Pulverized

Coal with Wet or Dry FGD

Fluidized Bed

Combustion (FBC)

Conventional Pulverized Coal (CPC) with Wet or Dry FGD

Existing Coal Steam Units with FGD

Upgrade Adjustment

HCl Removal Rate

99%

Without fabric filter: Same as

reported SO2 removal rate

up to a maximum of

95%

−−−

With fabric filter: 95%

Reported SO2 removal rate + 5% up to a maximum of

99%

If reported SO2 removal < 90%, unit incurs cost to upgrade

FGD, so that SO2 removal is 90%. Then,

the resulting HCl removal rate is 99%

−−− If reported SO2

removal is ≥ 90% and < 94%, then the unit

incurs a cost to upgrade FGD and the HCl removal rate is 99%. (The SO2

removal rate remains as reported.)

−−− If the reported SO2

removal rate is ≥ 94%, the unit incurs no

upgrade cost and the HCl removal rate is

99%.

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5.5.3 HCl Retrofit Emission Control Options Table 5‐20 Summary of HCl Emission Control Technology

Assumptions in EPA Base Case v4.10_PTox (Proposed Toxics Rule)

HCl Control Technology Options Applicability

Limestone Forced Oxidation (LSFO)

Scrubber Base case and policy case

Lime Spray Dryer (LSD) Base case and policy case

Dry Sorbent Injection (DSI)

Base case and policy case

Scrubber upgrade adjustment

To existing coal steam units with FGD in policy cases

analyzed for Toxics Rulemaking

All the retrofit options for HCl emission control are summarized in Table 5-20. The scrubber upgrade adjustment was discussed above in 5.5.2. The other options are discussed in detail in the following sections. 5.5.3.1 Wet and Dry FGD In addition to providing SO2 reductions, wet scrubbers (Limestone Forced Oxidation, LSFO) and dry scrubbers (Lime Spray Dryer, LSD) reduce HCl as well. For both LSFO and LSD the HCl removal rate is assumed to be 99% with a floor of 0.0001 lbs/MMBtu. This is summarized in columns 2-5 of Table 5-21.

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Table 5-21 Summary of Retrofit HCl (and SO2) Emission Control Performance Assumptions in v4.10_PTox (Proposed Toxics Rule) .

Performance Assumptions

Limestone Forced Oxidation (LSFO) Lime Spray Dryer (LSD) Dry Sorbent Injection (DSI)1

SO2 HCl SO2 HCl SO2 HCl

Percent Removal 96%

with a floor of 0.06 lbs/MMBtu

99% with a floor of

0.0001 lbs/MMBtu

92% with a floor of

0.065 lbs/MMBtu

99% with a floor of

0.0001 lbs/MMBtu


−−− With an

electrostatic percipitator2:

50%


with a floor of 0.0001 lbs/MMBtu

−−− With an

electrostatic percipitator2:

60% with a floor of

0.0001 lbs/MMBtu

Capacity Penalty -1.65% -0.70% -0.65%

Heat Rate Penalty 1.68% 0.71% 0.65%

Cost (2007$) See Table 5-3 and 5-4 See Table 5-3 and 5-4 See Tables D and E

Applicability Units ≥ 25 MW Units ≥ 25 MW Units ≥ 25 MW Sulfur Content Applicability Coals ≤ 2.0% Sulfur by Weight Coals ≤ 2.0 lb/mmBtu of SO2

Applicable Coal Types

BA, BB, BD, BE, BG, BH, SA, SB, SD, LD, LE, and LG

BA, BB, BD, BE, SA, SB, SD, LD, LE, and LG BA, BB, BD, SA, SB, SD, and LD

Notes 1. The cost and performance values shown in this table apply to existing units with pre-existing fabric filters or electrostatic precipitators. Units with neither ESP nor FF are assumed to have to install a fabric filter in order to qualify for the DSI retrofit. 2. The option to retrofit DSI on existing units with ESP was not offered in the runs performed for the current rulemaking.

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5.5.3.2 Dry Sorbent Injection Besides HCl reductions obtained from FGD, EPA Base Case v4.10_PTox includes dry sorbent injection (DSI), not previously included in the base case, as a retrofit option for achieving (in combination with a particulate control device) both SO2 and HCl removal. In DSI for HCl reduction, a dry sorbent is injected into the flue gas duct where it reacts with the HCl and SO2 in the flue gas to form a compound, which is then captured in a downstream fabric filter or electrostatic precipitator (ESP) and disposed of as waste. (A sorbent is a material that takes up another substance by either adsorption on its surface or absorption internally or in solution. A sorbent may also chemically react with another substance.) The sorbent assumed in the cost and performance characterization discussed in this section is trona, a sodium-rich material with major underground deposits found in Sweetwater County, Wyoming. Trona is typically delivered with an average particle size of 30 µm diameter, but can be reduced to about 15 µm through onsite in-line milling to increase its surface area and capture capability. Removal rate assumptions: The removal rate assumptions for DSI are summarized in Table 5-21. The assumptions shown in the last two columns of Table 5-21 were derived from assessments by EPA engineering staff in consultation with Sargent & Lundy. As indicated in this table, the assumed SO2 removal rate for DSI + ESP is 50% and for DSI + fabric filter is 70%. The assumed HCl removal rate is 60% for DSI + ESP and 90% for DSI + fabric filter. (This is noted in the next-to-the-last column in Table 5-21.) Although the option to retrofit DSI on existing units with ESP is shown in Table 5-21 it was not offered in the runs performed for the current rulemaking. Methodology for Obtaining DSI Control Costs: The engineering firm of Sargent & Lundy, whose analyses were used to update the cost of SO2 and post-combustion NOx controls in EPA Base Case , v4.10, performed similar engineering assessments of the cost of DSI retrofits with two alternative, associated particulate control devices, i.e., ESP and fabric filter (also called a “baghouse”). Their analysis of DSI noted that the cost drivers of DSI are quite different from those of wet or dry FGD. Whereas plant size and coal sulfur rates are key underlying determinants of FGD cost, sorbent feed rate and fly ash waste handling are the main drivers of the capital cost of DSI with plant size and coal sulfur rates playing a secondary role. Sorbent feed rate determines the amount of sorbent required and the size and extensiveness of the DSI installation. The sorbent feed rate needed to achieve a specified percent SO2 or HCl removal8 is firstly a function of the flue gas SO2 rate (which, in turn, is a function of the sulfur content of the coal burned, expressed in lbs of SO2/mmBtu ), the unit’s size and heat rate, and the sorbent particle size (which determines whether in-line milling is needed). The sorbent feed rate is also a function of the residence time of the sorbent in the flue gas stream and the extent of mixing and penetration of the sorbent in the flue gas. Residence time, penetration, and mixing are largely dependent on the type of particulate control device use (electrostatic precipitator or fabric filter).

8 For purposes of engineering calculations the percent removal is often translated into a corresponding “Normalized Stoichiometric Ratio” (NSR) associated with a particular percent removal, where the NSR is defined as

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In EPA Base Case v4.10_PTox the DSI sorbent feed rate and variable O&M costs are based on assumptions that a fabric filter and in-line trona milling are used, and that the SO2 removal rate is 60%. The corresponding HCl removal effect is assumed to be 90%, based on information from Solvay Chemicals (H. Davidson, Dry Sorbent Injection for Multi-pollutant Control Case Study, CIBO IECT VIII, August, 2010). The cost of fly ash waste handling, the other key contributor to DSI cost, is a function of the type of particulate capture device and the flue gas SO2 rate (which, as noted above, is itself a function of the sulfur content of the coal and the unit’s size and heat rate). Fly ash waste handling costs are also a function of the ash content and the higher heating value (HHV) of the coal. The governing variables of the key capital cost components of DSI are presented in Table 5-22. Table 5‐22. Capital Cost Components and Their Governing Variables for HCl Removal with DSI.

Module

Retrofit Difficulty

(1 = average)

Particulate Capture Type (ESP or

Baghouse)

Sorbent Particle Size

Require‐ment

(milled or unmilled)

Heat Rate(Btu/kWh)

SO2 Rate of coal (lb/

MMBtu)

Ash Content of Coal (percent)

Higher Heating Value (HHV) of Coal (Btu/lb)

Unit Size (MW)

Sorbent Feed Handling

X X X X X

Fly Ash Waste Handling

X X X X X X

Once the key variables for the two DSI modules are identified, they are used to derive costs for each base module component. These costs are then summed to obtain total bare module costs. The base installed cost for DSI includes

• All equipment • Installation • Buildings • Foundations • Electrical • Average retrofit difficulty • In-line milling equipment is assumed to be included

This total is increased by 15% to account for additional engineering and construction management costs, labor premiums, and contractor profits and fees. The resulting value is the capital, engineering, and construction cost (CECC) subtotal. To obtain the total project cost (TPC), the CECC subtotal is increased by 5% to account for owner’s home office costs, i.e., owner’s engineering, management, and procurement costs. Since DSI installations are

93

expected to be completed in less than a year, no Allowance for Funds used During Construction (AFUDC) is provided for DSI. The cost resulting from these calculations is the capital cost factor (expressed in $/kW) that is used in EPA Base Case v4.10_PTox. Variable Operating and Maintenance Costs (VOM): These are the costs incurred in running an emission control device. They are proportional to the electrical energy produced and are expressed in units of $ per MWh. For DSI, Sargent & Lundy identified three components of VOM: (a) costs for sorbent usage, (b) costs associated with waste production and disposal, (c) cost of additional power required to run the DSI control (often called the “parasitic load”). For DSI, sorbent usage is a function of the “Normalized Stoichiometric Ratio” and SO2 feed rate. As noted above the feed rate is a function of the SO2 rate of the coal and the unit’s size and heat rate. Total waste production involves the production of both reacted and unreacted sorbent and fly ash. Sorbent waste is a function of the sorbent feed rate with an adjustment for excess sorbent feed. Use of DSI makes the fly ash unsalable, which means that any fly ash produced must be landfilled along with the reacted and unreacted sorbent waste. Typical ash contents for each fuel are used to calculate a total fly ash production rate. The fly ash production is added to the sorbent waste to account for the total waste stream for the VOM analysis. For purposes of modeling, the total VOM includes the first two component costs noted in the previous paragraph, i.e., the costs for sorbent usage and the costs associated with waste production and disposal,. The last component – cost of additional power – is factored into IPM, not in the VOM value, but through a capacity and heat rate penalty as described in the next paragraph. Capacity and Heat Rate Penalty: The amount of electrical power required to operate the DSI is represented through a reduction in the amount of electricity that is available for sale to the grid. For example, if 0.65% of the unit’s electrical generation is needed to operate DSI, the generating unit’s capacity is reduced by 0.65%. This is the “capacity penalty.” At the same time, to capture the total fuel used in generation both for sale to the grid and for internal load (i.e., for operating the DSI device), the unit’s heat rate is scaled up such that a comparable reduction (0.65% in the previous example) in the new higher heat rate yields the original heat rate. The factor used to scale up the original heat rate is called “heat rate penalty.” It is a modeling procedure only and does not represent an increase in the unit’s actual heat rate (i.e., a decrease in the unit’s generation efficiency). As was the case for FGD in EPA Base Case v4.10, specific DSI heat rate and capacity penalties are calculated for each installation. For DSI the installation specific calculations take into account the additional power required by air blowers for the injection system, drying equipment for the transport air, and in-line milling equipment, if required. Fixed Operating and Maintenance Costs (FOM): These are the annual costs of maintaining an emission control. They represent expenses incurred regardless of the extent to which the emission control system is run. They are expressed in units of $ per kW per year. In calculating FOM Sargent & Lundy took into account labor and materials costs associated with operations, maintenance, and administrative functions. The following assumptions were made:

• FOM for operations is based on the number of operators needed which is a function of

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the size (i.e., MW capacity) of the generating unit. In general for DSI two (2) additional operators are assumed to be needed. • FOM for maintenance is a direct function of the DSI capital cost. • FOM for administration is a function of the FOM for operations and maintenance.

Table 5-23 presents the capital, VOM, and FOM costs as well as the capacity and heat rate penalties of a DSI retrofit for an illustrative and representative set of generating units with the capacities and heat rates indicated. Illustration worksheets of the detailed calculations performed to obtain the capital, VOM, and FOM costs for an example DSI appear in Appendix 5-4. The worksheets were developed by Sargent & Lundy9.

9These worksheets were extracted from Sargent & Lundy LLC, IPM Model – Revisions to Cost and Performance for APC Technologies: Complete Dry Sorbent Injection Cost Development Methodology (Project 12301-007), May 2010. The complete report is available for review and downloading at www.epa.gov/airmarkets/progsregs/epa-ipm/.

95

Table 5‐23. Illustrative Dry Sorbent Injection (DSI) Costs for Representative Sizes and Heat Rates Under Assumptions in EPA Base Case v4.10_PTox (Proposed Toxics Rule) .

Control Type

Heat Rate (Btu/ kWh)

SO2 Rate (lb/

MMBtu)

Capacity Penalty

(%)

Heat Rate

Penalty (%)

Variable O&M (mills/ kWh)

Capacity (MW) 100 300 500 700 1000

Capital Cost

($/kW)

Fixed O&M

($/kW-yr)

Capital Cost

($/kW)

Fixed O&M

($/kW-yr)

Capital Cost

($/kW)

Fixed O&M

($/kW-yr)

Capital Cost

($/kW)

Fixed O&M

($/kW-yr)

Capital Cost

($/kW)

Fixed O&M

($/kW-yr)

DSI - FF 9,000 2.0 0.64 0.65 6.05 122 2.25 55 0.87 38 0.57 30 0.43 28 0.36

Assuming Bituminous Coal

10,000 2.0 0.71 0.72 6.72 125 2.28 57 0.89 40 0.58 31 0.43 31 0.38

11,000 2.0 0.79 0.79 7.40 129 2.30 59 0.90 41 0.59 34 0.46 34 0.41

DSI - ESP 9,000 2.0 1.08 1.10 11.23 141 2.41 64 0.94 47 0.64 47 0.57 47 0.52

Assuming Bituminous Coal

10,000 2.0 1.20 1.22 12.47 145 2.44 66 0.96 52 0.68 52 0.61 52 0.56

11,000 2.0 1.32 1.34 13.72 149 2.48 68 0.98 58 0.73 58 0.65 58 0.60

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5.5.4 Fabric Filter (Baghouse) Cost Development Fabric filters are not endogenously modeled as a separate retrofit option in EPA Base Case v4.10_PTox, but are accounted for as a cost adder where they are required for particulate matter (PM), mercury, or HCl emission control. In EPA Base Case v4.10_PTox, an existing or new fabric filter particulate control device is a pre-condition for installing a DSI retrofit. In the v4.10_PTox policy case any unit that was retrofit by the model with DSI and did not have an existing fabric filter incurred the cost of installing a fabric filter. This cost was added to the DSI costs discussed in section 5.5.3.2. This section describes the methodology used by Sargent & Lundy to derive the cost of a fabric filter. The engineering cost analysis is based on a pulse-jet fabric filter which collects particulate matter on a fabric bag and uses air pulses to dislodge the particulate from the bag surface and collect it in hoppers for removal via an ash handling system to a silo. This is a mature technology that has been operating commercially for more than 25 years. “Baghouse” and “fabric filters” are used interchangeably to refer to such installations. Capital Cost: Two governing variables are used to derive the bare module capital cost of a fabric filter. The first of these is the “air-to-cloth” (A/C) ratio. The major driver of fabric filter capital cost, the A/C ratio is defined as the volumetric flow, (typically expressed in Actual Cubic Feet per Minute, ACFM) of flue gas entering the baghouse divided by the areas (typically in square feet) of fabric filter cloth in the baghouse. The lower the A/C ratio, e.g., A/C = 4.0 compared to A/C = 6.0, the greater the area of the cloth required and the higher the cost for a given volumetric flow. The other determinant of capital cost is the flue gas volumetric flow rate (in ACFM) which is a function of the type of coal burned and the unit’s size and heat rate. The capital cost for fabric filters include:

• Duct work modifications, • Foundations, • Structural steel, • Induced draft (ID) fan modifications or new booster fans, and • Electrical modifications.

After the bare installed total capital cost is calculated, it is increased by 20% to account for additional engineering and construction management costs, labor premiums, and contractor profits and fees. The resulting value is the capital, engineering, and construction cost (CECC) subtotal. To obtain the total project cost (TPC), the CECC subtotal is increased by 5% to account for owner’s home office costs, i.e., owner’s engineering, management, and procurement costs, and by another 6% to account for Allowance for Funds used During Construction (AFUDC) which is premised on a 2-year project duration. The cost resulting from these calculations is the capital cost factor (expressed in $/kW). Fabric filter capital costs are implemented in EPA Base Case v4.10_PTox as an FOM adder. Plants that install fabric filters incur a total FOM charge which includes the true FOM associated with the fabric filter plus a capital cost FOM Adder derived by multiplying the capital cost by a capital

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charge rate of 11.3%, i.e., Total FOM = True FOM + Capital Cost FOM Adder

where the FOM Adder = Capital Cost X Capital Charge Rate = Capital Cost X 11.3% In EPA Base Case v4.10_PTox the capital cost of a fabric filter is based on the use of a “polishing” fabric filter designed with A/C=6.0. This basis results in a capital cost that is at least 10% less than the cost of a design with A/C=4.0, and assumes that the existing ESP remains in place and active. Variable Operating and Maintenance Costs (VOM): For fabric filters the VOM is strictly a function of the costs of the fabric filter bag and cage translated in a $/MWhr cost based on the filter and bag replacement cycle for a specified A/C ratio. For units whose A/C ratio = 6.0, the replacement cycle for the bag is 3 years and the cage is 9 years, whereas for units whose A/C ratio = 4.0, the bag and cage replacement cycles are 5 and 10 years respectively. Capacity and Heat Rate Penalty: Conceptually, the capacity and heat rate penalties for fabric filters represent the amount of electrical power required to operate the baghouse and are calculated by the same procedure used when calculating the capacity and heat rate penalty for DSI as described in section 5.5.3.2. The resulting capacity and heat rate penalties are both 0.6%. However, since fabric filters were not endogenously modeled as a retrofit option, but simply added to the DSI costs for generating units that do not have an existing baghouse, the capacity and heat rate penalties described here were not factored into the representation of fabric filters in EPA Base Case v4.10_PTox. Fixed Operating and Maintenance Costs (FOM): Sargent & Lundy’s engineering analysis indicated that no additional operations staff would be required for a baghouse. Consequently the FOM strictly includes two components:

• FOM for maintenance is a direct function of the DSI capital cost. • FOM for administration is a function of the FOM for operations (which is zero) and maintenance.

Table 5-24 presents the capital, VOM, and FOM costs for fabric filters as represented in EPA Base Case v4.10_PTox for an illustrative set of generating units with a representative range of capacities and heat rates. Worksheets illustrating the detailed calculations performed to obtain the capital, VOM, and FOM costs for two example fabric filters (A/C Ratio = 4.0 and A/C Ratio = 6.0) appear in Appendix 5-5. The worksheets were developed by Sargent & Lundy10.

10 These worksheets were extracted from Sargent & Lundy LLC, IPM Model – Revisions to Cost and Performance for APC Technologies: Particulate Control Cost Development Methodology (Project 12301-009), October 2010. The complete report is available for review and downloading at www.epa.gov/airmarkets/progsregs/epa-ipm/.

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Table 5‐24. Illustrative Fabric Filter (Baghouse) Costs for Representative Sizes and Heat Rates Under Assumptions in EPA Base Case v4.10_PTox (Proposed Toxics Rule) .

Coal Type Heat Rate (Btu/ kWh)

Capacity Penalty

(%)

Heat Rate

Penalty (%)

Variable O&M (mills/ kWh)

Capacity (MW) 100 300 500 700 1000

Capital Cost

($/kW)

Fixed O&M

($/kW-yr)

Capital Cost

($/kW)

Fixed O&M

($/kW-yr)

Capital Cost

($/kW)

Fixed O&M

($/kW-yr)

Capital Cost

($/kW)

Fixed O&M

($/kW-yr)

Capital Cost

($/kW)

Fixed O&M

($/kW-yr)

Bituminous 9,000

0.60 0.60 0.15 188 0.8 153 0.6 139 0.6 130 0.6 122 0.5

10,000 205 0.9 167 0.7 151 0.6 141 0.6 132 0.6 11,000 221 0.9 180 0.8 163 0.7 153 0.6 143 0.6

Notes on Implementation 1. Plant specific fabric filter capital costs shown in this table are implemented in EPA Base Case v4.10_PTox as an FOM adder. Plants that install fabric filters incur a total FOM charge which includes the true FOM component shown in the above table plus a capital cost FOM Adder derived by multiplying the capital cost in the table above by a capital charge rate 11.3%, i.e., Total FOM = True FOM + Capital Cost FOM Adder where the FOM Adder = Capital Cost X Capital Charge Rate = Capital Cost X 11.3%. Plants that install fabric filters also incur the additional VOM costs shown in the above table. 2. Since the fabric filter costs were not endogenously modeled as a retrofit option, the capacity and heat rate penalties shown in the above table were not represented in the model.

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Appendix 5-3 Example Cost Calculation Worksheets for Three Activated Carbon Injection (ACI) Options for Mercury Emission Control in EPA Base Case v4.10_PTox (Proposed Toxics Rule)

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101

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Appendix 5-4 Example Cost Calculation Worksheet for Dry Sorbent Injection (DSI) for HCl (and SO2) Emissions Control in EPA Base Case v4.10_PTox (Proposed Toxics Rule)

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Appendix 5-5 Example Cost Calculation Worksheets for Fabric Filters (A/C Ratio = 4.0 and A/C Ratio = 6.0) in EPA Base Case v4.10_PTox (Proposed Toxics Rule)

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Documentation Supplement to Chapter 9 (“Coal”) To allow HCl emissions to be modeled, the chlorine content of the coal offered to electric generating units in EPA Base Case v4.10_PTox had to be represented in the model. This involved adding data on coal chlorine content and then re-running the clustering set-up procedure, which makes the coal quality data usable in the model. The following discussion will refer to the HCl emission rate (in lbs/MMBtu) of the coal and the chlorine content of the coal interchangeably. The HCl emission rate is obtained by multiplying the chlorine content of the coal by a factor of 1.03. This is an alternate way of expressing chlorine content and is consistent with using an SO2 emission rate (in lbs/MMBtu) to express the sulfur content of the coal. For EPA Base Case v4.10 the clustering procedure was performed on SO2 and mercury data only. For Base Case v4.10_PTox it had to be performed jointly on the SO2, mercury, and HCl data. The addition of HCl data and the consequent re-clustering are reflected in complete updates of Tables 9-5 through 9-9 and the addition of a new table for HCl equivalent to Tables 9-6 through 9-9. These tables show the SO2, mercury, ash, HCl, and CO2 emission factors that result after the clustering procedure is performed. The enhancements made to accommodate the HCl data in the model are documented below in the form of a mark-up of sections 9.1.3 (“Coal Quality Characteristics”) and 9.1.4 (“Emission Factors”) of the v4.10 documentation report “Documentation for EPA Base Case v4.10 Using the Integrated Planning Model” (August 2010). Substantive changes to the original text are shown in red, boldface italics. Revised Tables 9-5 through 9-9 and the new HCl emission factor Table 9-10 are shown without special highlighting. Note: For EPA Base Case v4.10_PTox the only coal assumptions and procedures which changed are those presented in sections 9.1.3 and 9.1.4 below. The other unchanged sections of Chapter 9 can be found at www.epa.gov/airmarkets/progsregs/epa-ipm/docs/v410/Chapter9.pdf. ************************************************************************************************************* 9 Coal ● ● ● 9.1.3 Coal Quality Characteristics Coal varies by heat content, SO2 content, HCl content, and mercury content among other characteristics. To capture differences in the sulfur and heat content of coal, a two letter “coal grade” nomenclature is used. The first letter indicates the “coal rank” (bituminous, sub-bituminous, or lignite) with their associated heat content ranges (as shown in Table 9-3). The second letter indicates their “sulfur grade,” i.e., the SO2 ranges associated with a given type of coal. (The sulfur grades and associated SO2 ranges are shown in Table 9-4.)

Table 9-3 Coal Rank Heat Content Ranges

Coal Type Heat Content (Btu/lb) Classification

Bituminous >10,260 – 13,000 B

Sub-bituminous > 7,500 – 10,260 S

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Lignite less than 7,500 L

Table 9-4 Coal Grade SO2 Content Ranges

SO2 Grade SO2 Content Range (lbs/MMBtu) A 0.00 – 0.80 B 0.81 – 1.20 D 1.21 – 1.66 E 1.67 – 3.34 G 3.35 – 5.00 H > 5.00

The assumptions in EPA Base Case v4.10_PTox regarding the heat, HCl, mercury, SO2, and ash content of coal are derived from EPA’s “Information Collection Request for Electric Utility Steam Generating Unit Mercury Emissions Information Collection Effort” (ICR)11. A two-year effort initiated in 1998 and completed in 2000, the ICR had three main components: (1) identifying all coal-fired units owned and operated by publicly-owned utility companies, Federal power agencies, rural electric cooperatives, and investor-owned utility generating companies, (2) obtaining “accurate information on the amount of mercury contained in the as-fired coal used by each electric utility steam generating unit… with a capacity greater than 25 megawatts electric, as well as accurate information on the total amount of coal burned by each such unit,”, and (3) obtaining data by coal sampling and stack testing at selected units to characterize mercury reductions from representative unit configurations. Data regarding the SO2, chlorine, and ash content of the coal used were obtained along with mercury content. The 1998-2000 ICR resulted in more than 40,000 data points indicating the coal type, sulfur content, mercury content, ash content, chlorine content, and other characteristics of coal burned at coal-fired utility units greater than 25 MW. 9.1.4 Emission Factors To make this data usable in EPA Base Case v4.10_PTox, the ICR data points were first grouped by IPM coal grades and IPM coal supply regions. Using the grouped ICR data, the average heat, SO2, mercury, HCl, and ash content were calculated for each coal grade/supply region combination. In instances where no data were available for a particular coal grade in a specific supply region, the national average SO2, HCl, and mercury values for the coal grade were used as the region’s values. The resulting values are shown in Table 9-5.

11 Data from the ICR can be found at www.epa.gov/ttn/atw/combust/utiltox/mercury.html.

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Table 9-5 Coal Quality Characteristics by Supply Region and Coal Grade in EPA Base Case v4.10_PToxCoal

Supply Region

Coal Grade

Heat Content (MMBtu/Ton)

SO2Content

(lbs/MMBtu)

Mercury Content

(lbs/TBtu)

Ash Content

(lbs/MMBtu) HCl Content(lbs/MMBtu)

Cluster Number

AL BB 24.82 1.1 4.2 9.8 0.012 1 BD 24.00 1.4 7.3 10.8 0.029 6 BE 23.82 2.7 12.6 10.7 0.028 1

AZ BB 24.64 1.1 5.3 7.9 0.067 2

CG BA 21.49 0.7 3.1 7.3 0.040 3 BB 22.01 0.9 4.1 8.4 0.021 1

CR BA 25.50 0.7 3.5 7.0 0.027 5 BD 22.20 1.4 7.0 8.3 0.096 6

CU BA 23.80 0.7 2.6 6.3 0.007 1 BB 23.22 0.9 4.0 7.8 0.009 1 BD 23.21 1.3 3.1 8.1 0.008 1

IL BE 23.00 2.2 6.5 6.6 0.214 3 BG 23.01 4.6 6.5 8.1 0.113 2 BH 22.19 5.6 5.4 9.1 0.103 1

IN

BD 22.62 1.4 3.8 7.4 0.030 5 BE 23.43 2.3 5.2 8.0 0.037 3 BG 23.37 4.3 7.2 8.2 0.028 2 BH 23.41 6.1 7.1 8.6 0.019 2

KE

BA 25.32 0.7 3.0 6.1 0.114 4 BB 25.79 1.0 4.8 6.4 0.112 5 BD 25.33 1.4 6.0 7.4 0.087 4 BE 25.14 2.1 7.9 7.7 0.076 4 BG 24.09 3.8 12.0 10.2 0.041 3

KS BG 25.32 4.8 4.1 8.5 0.133 4

KW

BD 24.23 1.6 5.6 6.2 0.281 4 BE 24.45 2.8 7.1 7.4 0.199 3 BG 23.93 4.5 6.9 8.0 0.097 2 BH 22.84 5.7 8.2 10.2 0.054 3

LA LE 14.09 2.5 7.3 17.1 0.014 2

MD

BB 24.64 1.1 5.3 7.9 0.067 2 BD 26.32 1.6 7.8 9.5 0.029 6 BE 24.85 2.8 15.6 11.7 0.072 6 BG 23.26 3.6 16.6 16.6 0.018 5

ME LD 13.36 1.4 8.6 11.3 0.019 1

MP SA 18.90 0.6 4.2 4.0 0.007 1 SD 17.23 1.5 4.5 10.1 0.006 1

MS LE 13.19 2.8 12.4 21.5 0.018 1 MT BB 21.00 1.1 5.3 7.9 0.067 2

ND LD 13.70 1.5 6.4 10.7 0.012 1 LE 13.46 2.3 8.3 12.8 0.014 2

NS BB 26.40 1.1 5.3 7.9 0.067 2 BD 18.10 1.6 5.5 19.6 0.005 4 BE 18.10 1.8 8.2 18.8 0.006 4

OH

BB 24.68 1.1 5.7 9.8 0.083 6 BD 25.55 1.4 6.4 10.3 0.065 4 BE 25.24 3.1 18.7 7.1 0.075 5 BG 24.34 4.0 18.5 8.0 0.072 5 BH 23.92 6.4 13.9 9.1 0.058 4

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Table 9-5 (cont’d): Coal Quality Characteristics by Supply Region and Coal Grade in EPA Base Case v4.10_PTox

Coal Supply Region

Coal Grade Heat

Content (MMBtu/Ton)

SO2Content

(lbs/MMBtu)

Mercury Content

(lbs/TBtu)

Ash Content

(lbs/MMBtu) HCl Content(lbs/MMBtu)

Cluster Number

OK BE 22.15 2.7 25.8 11.3 0.033 2

PC

BD 25.06 1.4 21.7 49.3 0.066 2 BE 25.66 2.6 18.0 9.2 0.096 5 BG 25.33 3.8 21.5 9.6 0.092 1 BH 23.39 6.3 34.7 13.9 0.149 5

PW BD 24.26 1.6 11.2 10.0 0.086 3 BE 26.22 2.5 8.4 5.4 0.091 4 BG 25.86 3.7 8.6 6.5 0.059 2

TN BB 24.18 1.1 3.8 10.4 0.084 3 BD 23.91 1.3 6.3 10.4 0.083 4 BE 26.75 2.1 8.4 6.5 0.043 4

TX LD 13.06 1.6 12.0 22.3 0.028 2 LE 13.22 3.0 14.7 25.6 0.020 1 LG 12.27 3.9 14.9 25.5 0.036 1

UT

BA 23.68 0.7 4.4 7.4 0.015 2 BB 23.23 0.9 3.9 8.6 0.016 1 BD 23.05 1.4 4.4 10.5 0.026 5 BE 25.06 2.3 9.2 7.4 0.095 4

VA

BA 22.70 0.7 3.5 7.0 0.027 5 BB 25.97 1.0 4.6 7.0 0.054 5 BD 25.76 1.4 5.7 8.0 0.028 4 BE 26.03 2.1 8.4 8.1 0.028 4

WG BB 21.67 1.1 1.8 5.6 0.005 4 SD 18.50 1.3 4.3 10.0 0.008 2

WH SA 17.43 0.6 5.6 5.5 0.012 2 SB 17.43 0.9 6.4 6.5 0.012 1

WL SB 17.15 0.9 6.4 6.5 0.012 1

WN

BD 25.01 1.5 10.3 9.2 0.100 3 BE 25.67 2.5 10.3 7.9 0.092 4 BG 26.03 4.0 9.3 6.9 0.075 2 BH 25.15 6.1 8.8 9.6 0.045 3

WS

BA 26.20 0.7 3.5 7.0 0.027 5 BB 24.73 1.1 5.7 9.2 0.091 6 BD 24.64 1.3 8.1 9.3 0.098 6 BE 24.38 1.9 8.8 9.9 0.102 4 BG 25.64 4.7 7.1 6.4 0.051 2

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Next, a clustering algorithm was used to further aggregate the data in EPA Base Case v4.10_PTox, for model size management purposes. The clustering analysis was performed on the mercury, HCl, and SO2 data shown in Table 9-5 using the SAS statistical software package. Clustering analysis places objects into groups or clusters, such that data in a given cluster tend to be similar to each other and dissimilar to data in other clusters. The clustering analysis involved two steps. (In the following write-up BG coal is used to illustrate how the procedure worked.) First, the number of clusters of mercury, HCl, and SO2 concentrations for each IPM coal type was determined based on the range in average mercury, HCl, and SO2 concentrations across all coal supply regions for a specific coal type. In EPA Base Case v4.10 each coal type used either one or two clusters. After adding the HCl data in EPA Base Case v4.10_PTox, three coal grades (BB, BD, and BE) were assigned 6 clusters, another three coal grades (BA, BG, and BH) were assigned 5 clusters, four coal grades (SA, SD, LD, LE) were assigned 2 clusters, and two grades (SB, and LG) were assigned one cluster each. The total number of clusters for each coal grade was limited to keep the model size and run time within feasible limits. (Whereas three clusters were used for BG coal in v4.10, with the addition of HCl as a clustering parameter, five clusters were needed for BG coal in v4.10_PTox.) Second, for each coal grade the clustering procedure was applied to all the regional SO2, HCl, and mercury values shown in Table 9-5 for that coal grade. (In the BG coal example there are 11 such regional SO2, HCl, and mercury values.) Using the SAS cluster procedure, each of the constituent regional values was assigned to a cluster and the cluster average SO2, HCl, and mercury values were recorded. The resulting values are shown in Tables 9-6, 9-7, and Table 9-10. (For BG coal the Cluster #1 average SO2, HCl, and mercury values are 3.79 lbs/MMBtu, 0.092 lbs/MMBtu, and 21.54 lbs/TBtu respectively. The Cluster #2 average SO2, HCl, and mercury values are 4.28 lbs/MMBtu, 0.070 lbs/MMBtu, and 7.60 lbs/TBtu respectively. The Cluster #3 average SO2, HCl, and mercury values are 3.79 lbs/MMBtu, 0.041 lbs/MMBtu, and 11.99 lbs/TBtu respectively. The Cluster #4 average SO2, HCl, and mercury values are 4.84 lbs/MMBtu, 0.133 lbs/MMBtu, and 4.09 lbs/TBtu respectively. The Cluster #5 average SO2, HCl, and mercury values are 3.78 lbs/MMBtu, 0.045 lbs/MMBtu, and 17.59 lbs/TBtu respectively.) Although not used in determining the clusters, ash and CO2 values were calculated for each of the clusters. These values are shown in Table 9-8 and Table 9-9. (The CO2 values were derived from data in the Energy Information Administration’s Annual Energy Outlook 2009 (AEO 2009), not from data collected in the ICR.) IPM input files retain the mapping between different coal grade/supply region combinations and the clusters. The mapping can be seen in the last column of Table 9-5 which shows the cluster number associated with the coal grade/supply region combination indicated in the first and second columns of this table. (For BG coal, the SAS cluster procedure mapped supply region PC into Cluster #1, IL, IN, KW, PW,WN and WS into Cluster #2, KE into Cluster #3, KS into Cluster #4, and MD and OH into Cluster #5.. See Figure 9-2 for an illustration of this mapping.) Table 9-6 to Table 9-10 show the SO2, mercury, ash, CO2, and HCl values that are assigned to coal grades and regions based on this cluster mapping. The values shown in Table 9-6 to Table 9-10 are used in EPA Base Case v4.10 for calculating emissions.

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Table 9-6 SO2 Emission Factors of Coal Used in EPA Base Case v4.10_PTox

Coal Type by Sulfur Grade Sulfur Emission Factors (lbs/MMBtu)

Cluster #1

Cluster #2

Cluster # 3

Cluster #4

Cluster # 5

Cluster # 6

Low Sulfur Eastern Bituminous (BA) 0.70 0.67 0.72 0.74 0.68 -- Low Sulfur Western Bituminous (BB) 0.95 1.05 1.14 1.13 1.04 1.08 Low Medium Sulfur Bituminous (BD) 1.31 1.42 1.51 1.46 1.41 1.41 Medium Sulfur Bituminous (BE) 2.68 2.68 2.46 2.19 2.82 2.78 High Sulfur Bituminous (BG) 3.79 4.28 3.79 4.84 3.78 -- High Sulfur Bituminous (BH) 5.58 6.15 5.91 6.43 6.29 -- Low Sulfur Subbituminous (SA) 0.62 0.58 -- -- -- -- Low Sulfur Subbituminous (SB) 0.94 -- -- -- -- -- Low Medium Sulfur Subbituminous (SD) 1.49 1.33 -- -- -- --

Low Medium Sulfur Lignite (LD) 1.46 1.61 -- -- -- -- Medium Sulfur Lignite (LE) 2.88 2.38 -- -- -- -- High Sulfur Lignite (LG) 3.91 -- -- -- -- --

Table 9-7 Mercury Emission Factors of Coal Used in EPA Base Case v4.10_PTox

Coal Type by Sulfur Grade Mercury Emission Factors (lbs/Tbtu)

Cluster #1

Cluster #2

Cluster #3

Cluster #4

Cluster # 5

Cluster # 6



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Table 9-8 Ash Emission Factors of Coal Used in EPA Base Case v4.10_PTox

Coal Type by Sulfur Grade Ash Emission Factors (lbs/MMBtu)

Cluster #1

Cluster #2

Cluster #3

Cluster #4

Cluster # 5

Cluster # 6



Table 9-9 CO2 Emission Factors of Coal Used in EPA Base Case v4.10_PTox

Coal Type by Sulfur Grade CO2 Emission Factors (lbs/MMBtu)

Cluster #1

Cluster #2

Cluster #3

Cluster #4

Cluster # 5

Cluster # 6



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Table 9-10 HCl Emission Factors of Coal Used in EPA Base Case v4.10_PTox

Coal Type by Sulfur Grade HCl Emission Factors (lbs/MMBtu)

Cluster #1

Cluster #2

Cluster #3

Cluster #4

Cluster # 5

Cluster # 6



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Figure 9-2 Cluster Mapping Example – BG Coal

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